Document and Entity Information	12 Months Ended
Document and Entity Information	Dec. 31, 2016
Document And Entity Information [Abstract]
Document Type	8-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Entity Registrant Name	DCP MIDSTREAM, LP
Entity Central Index Key	0001338065

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 1	$ 3
Accounts receivable:
Trade, net of allowance for doubtful accounts of $4 million	652	448
Affiliates	134	75
Other	6	21
Inventories	72	51
Unrealized gains on derivative instruments	42	156
Collateral cash deposits	71	7
Other	16	43
Total current assets	994	804
Property, plant and equipment, net	9,069	9,428
Goodwill	236	242
Intangible assets, net	137	149
Investments in unconsolidated affiliates	2,969	2,992
Unrealized gains on derivative instruments	5	19
Other long-term assets	201	251
Total assets	13,611	13,885
Accounts payable:
Trade	677	480
Affiliates	48	40
Other	10	25
Current maturities of long-term debt	500	0
Unrealized losses on derivative instruments	91	69
Accrued interest	72	72
Accrued taxes	49	38
Accrued wages and benefits	72	71
Capital spending accrual	20	20
Other	84	84
Total current liabilities	1,623	899
Long-term debt	4,907	5,669
Unrealized losses on derivative instruments	1	12
Deferred income taxes	28	26
Other long-term liabilities	199	187
Total liabilities	6,758	6,793
Commitments and contingent liabilities
Equity:
Predecessor equity	4,220	4,287
Limited partners (114,749,848 and 114,742,948 common units issued and outstanding, respectively)	2,591	2,762
General partner	18	18
Accumulated other comprehensive loss	(8)	(8)
Total partners’ equity	6,821	7,059
Non-controlling interests	32	33
Total equity	6,853	7,092
Total liabilities and equity	$ 13,611	$ 13,885

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating revenues:
Sales of natural gas, NGLs and condensate to affiliates	$ 6,269	$ 6,779	$ 13,420
Transportation, storage and processing to affiliates	647	532	517
Trading and marketing (losses) gains, net	(23)	119	88
Total operating revenues	6,893	7,430	14,025
Operating costs and expenses:
Purchases of natural gas and NGLs from affiliates	5,461	5,981	11,828
Operating and maintenance expense	670	732	773
Depreciation and amortization expense	378	377	348
General and administrative expense	292	281	277
Asset impairments	0	912	18
Other (income) expense, net	(65)	10	7
(Gain) loss on sale of assets, net	(35)	(42)	7
Restructuring costs	13	11	0
Total operating costs and expenses	6,714	8,262	13,258
Operating income (loss)	179	(832)	767
Interest expense, net	(321)	(320)	(287)
Earnings from unconsolidated affiliates	282	184	82
Income (loss) before income taxes	140	(968)	562
Income tax (expense) benefit	(46)	102	(11)
Net income (loss)	94	(866)	551
Net income attributable to non-controlling interests	(6)	(5)	(4)
Net income (loss) attributable to partners	88	(871)	547
Net loss (income) attributable to predecessor operations	224	1,099	(130)
General partner’s interest in net income	(124)	(124)	(114)
Net income allocable to limited partners	$ 188	$ 104	$ 303
Net income per limited partner unit — basic and diluted (in dollars per share)	$ 1.64	$ 0.91	$ 2.84
Weighted-average limited partner units outstanding - basic (in shares)	114,700	114,600	106,600
Weighted-average limited partner units outstanding - diluted (in shares)	114,700	114,600	106,600
Third Party
Operating revenues:
Sales of natural gas, NGLs and condensate to affiliates	$ 5,317	$ 6,014	$ 11,390
Transportation, storage and processing to affiliates	647	532	517
Operating costs and expenses:
Purchases of natural gas and NGLs from affiliates	4,978	5,563	11,363
Affiliated Entity
Operating revenues:
Sales of natural gas, NGLs and condensate to affiliates	952	765	2,030
Operating costs and expenses:
Purchases of natural gas and NGLs from affiliates	$ 483	$ 418	$ 465

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 4	$ 4
Common unitholders, units issued (in shares)	114,749,848	114,742,948
Common unitholders, units outstanding (in shares)	114,749,848	114,742,948

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (39)	$ 89	$ (21)	$ 65	$ (382)	$ 24	$ (491)	$ (17)	$ 94	$ (866)	$ 551
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings									0	1	2
Total other comprehensive income									0	1	2
Total comprehensive income (loss)									94	(865)	553
Total comprehensive income attributable to non-controlling interests									(6)	(5)	(4)
Total comprehensive income (loss) attributable to partners									$ 88	$ (870)	$ 549

Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Accumulated Other Comprehensive Loss	Non-controlling Interests	Limited Partners	General Partner
Beginning balance (Predecessor Equity) at Dec. 31, 2013	$ 2,406
Beginning balance at Dec. 31, 2013	4,385	$ (11)	$ 34	$ 1,948	$ 8
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss) \| Predecessor Equity	130
Net income (loss)	551		4	303	114
Other comprehensive (loss) income \| Predecessor Equity	0
Other comprehensive (loss) income	2	2
Net change in parent advances \| Predecessor Equity	(347)
Net change in parent advances	(347)
Issuance of 4,497,158 units to DCP Midstream, LLC and affiliates	225			225
Excess purchase price over carrying value of acquired net assets	(178)			(178)
Issuance of common units	1,002			1,002
Distributions to limited partners and general partner	(420)			(316)	(104)
Distributions to noncontrolling interests	(5)		(5)
Ending balance (Predecessor Equity) at Dec. 31, 2014	2,189
Ending balance at Dec. 31, 2014	5,215	(9)	33	2,984	18
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss) \| Predecessor Equity	(1,099)
Net income (loss)	(866)		5	104	124
Other comprehensive (loss) income	1	1
Net change in parent advances \| Predecessor Equity	3,197
Net change in parent advances	3,197
Issuance of common units	31			31
Distributions to limited partners and general partner	(482)			(358)	(124)
Distributions to noncontrolling interests	(5)		(5)
Contributions from DCP Midstream, LLC	1			1
Ending balance (Predecessor Equity) at Dec. 31, 2015	4,287
Ending balance at Dec. 31, 2015	7,092	(8)	33	2,762	18
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss) \| Predecessor Equity	(224)
Net income (loss)	94		6	188	124
Other comprehensive (loss) income	0
Net change in parent advances \| Predecessor Equity	157
Net change in parent advances	157
Distributions to limited partners and general partner	(483)			(359)	(124)
Distributions to noncontrolling interests	(7)		(7)
Ending balance (Predecessor Equity) at Dec. 31, 2016	4,220
Ending balance at Dec. 31, 2016	$ 6,853	$ (8)	$ 32	$ 2,591	$ 18

Consolidated Statements of Changes in Equity (Parenthetical) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Issuance of common units (in shares)	793,080	20,407,571
Issuance of units, acquisitions (in shares)		4,497,158

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING ACTIVITIES:
Net income (loss)	$ 94	$ (866)	$ 551
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	378	377	348
Earnings from unconsolidated affiliates	(282)	(184)	(82)
Distributions from unconsolidated affiliates	356	217	141
Net unrealized losses (gains) on derivative instruments	139	(46)	(43)
(Gain) loss on sale of assets	(35)	(42)	7
Asset impairments	0	912	18
Other, net	68	(68)	36
Change in operating assets and liabilities, which provided cash, net of effects of acquisitions:
Accounts receivable	(247)	479	400
Inventories	(21)	29	16
Accounts payable	199	(381)	(467)
Other, net	(4)	15	(108)
Net cash provided by operating activities	645	442	817
INVESTING ACTIVITIES:
Capital expenditures	(144)	(811)	(1,384)
Investments in unconsolidated affiliates, net	(53)	(64)	(161)
Proceeds from sale of assets	163	164	30
Net cash used in investing activities	(34)	(711)	(1,515)
FINANCING ACTIVITIES:
Proceeds from long-term debt	3,353	7,216	719
Payments of long-term debt	(3,628)	(7,196)	0
Payments of commercial paper, net	0	(1,012)	(288)
Payments of deferred financing costs	(5)	(4)	(12)
Proceeds from issuance of common units, net of offering costs	0	31	1,001
Net change in advances to predecessor from DCP Midstream, LLC	157	1,697	(301)
Distributions to limited partners and general partner	(483)	(482)	(420)
Distributions to non-controlling interests	(7)	(5)	(5)
Net cash (used in) provided by financing activities	(613)	245	694
Net change in cash and cash equivalents	(2)	(24)	(4)
Cash and cash equivalents, beginning of period	3	27	31
Cash and cash equivalents, end of period	$ 1	$ 3	$ 27

Description of Business and Basis of Presentation	12 Months Ended
Description of Business and Basis of Presentation	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business and Basis of Presentation	Description of Business and Basis of Presentation DCP Midstream, LP, with its consolidated subsidiaries, or "us", "we", "our" or "the Partnership" is a Delaware limited partnership formed in 2005 by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. Our Partnership includes our Gathering and Processing and Logistics and Marketing segments. For additional information regarding these segments, see Note 21 - Business Segments. Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and is 100% owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Phillips 66 and its affiliates and 50% by Enbridge, Inc. and its affiliates, or Enbridge. During the third quarter of 2016, Spectra Energy entered into an Agreement and Plan of Merger (the "Merger Agreement") with Enbridge and completed the merger during the first quarter of 2017. DCP Midstream, LLC directs our business operations through its ownership and control of the General Partner. As of December 31, 2016 DCP Midstream, LLC owned approximately 21.4% of us, including limited partner and general partner interests. On December 30, 2016, we entered into a Contribution Agreement (the “Contribution Agreement”) with DCP Midstream, LLC and DCP Midstream Operating, LP (the “Operating Partnership”), a wholly owned subsidiary of the Partnership. The transactions and documents contemplated by the Contribution Agreement are collectively referred to hereafter as the “Transaction.” The Transaction closed effective January 1, 2017. Our predecessor results consist of all of the ownership interests of DCP Midstream, LLC in all of its subsidiaries that owned operating assets ("The DCP Midstream Business"), which we acquired from DCP Midstream, LLC on January 1, 2017. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information, similar to the pooling method. Accordingly, our consolidated financial statements include the historical results of The DCP Midstream Business for all periods presented. We recognize transfers of net assets between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. The amount of the purchase price deficit of DCP Midstream, LLC’s basis in the net assets is recognized as an addition to limited partners’ equity. The financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity. Following the Transaction, DCP Midstream, LLC owned approximately 38.1% of us, including limited partner and general partner interests. For additional information regarding the Transaction, see Note 4 - Acquisitions. The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. All intercompany balances and transactions have been eliminated in consolidation.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Use of Estimates - Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates.

Cash and Cash Equivalents - We consider investments in highly liquid financial instruments purchased with an original stated maturity of 90 days or less and temporary investments of cash in short-term money market securities to be cash equivalents.

Allowance for Doubtful Accounts - Management estimates the amount of required allowances for the potential non-collectability of accounts receivable generally based upon the number of days past due, past collection experience and consideration of other relevant factors. However, past experience may not be indicative of future collections and therefore additional charges could be incurred in the future to reflect differences between estimated and actual collections.

Inventories - Inventories, which consist primarily of NGLs and natural gas, are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory.

Accounting for Risk Management Activities and Financial Instruments - We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives may be designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or normal purchases or normal sales. The remaining other non-trading derivatives, which are related to asset-based activities for which hedge accounting or the normal purchase or normal sale exception is not elected, are recorded at fair value in the consolidated balance sheets as unrealized gains or unrealized losses in derivative instruments, with changes in fair value recognized in the consolidated statements of operations. For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the consolidated statements of operations are as follows:



Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Trading Derivatives	Mark-to-market method (a)	Net basis in trading and marketing gains and losses
Non-Trading Derivatives:
Cash Flow Hedge	Hedge method (b)	Gross basis in the same consolidated statements of operations category as the related hedged item

Fair Value Hedge	Hedge method (b)	Gross basis in the same consolidated statements of operations category as the related hedged item

Normal Purchases or Normal Sales	Accrual method (c)	Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale

Other Non-Trading Derivative Activity	Mark-to-market method (a)	Net basis in trading and marketing gains and losses, net

______________


(a)	Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in trading and marketing gains and losses, net during the current period.

(b)

Hedge method - An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the effective portion until the service is provided or the associated delivery impacts earnings. For fair value hedges, the change in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations in the same category as the related hedged item.


(c)	Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery impacts earnings.

Cash Flow and Fair Value Hedges - For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge. In addition, we formally assess both at the inception of the hedging relationship and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.

The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. The change in fair value of the effective portion of a derivative designated as a cash flow hedge is recorded in partners’ equity in accumulated other comprehensive income, or AOCI, and the ineffective portion is recorded in the consolidated statements of operations. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations in the same line item as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.

The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains or unrealized losses on derivative instruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the results of operations.

Valuation - When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical relationships with quoted market prices and the expected relationship with quoted market prices.

Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

Property, Plant and Equipment - Property, plant and equipment are recorded at historical cost. The cost of maintenance and repairs, which are not significant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.

Capitalized Interest - We capitalize interest during construction of major projects. Interest is calculated on the monthly outstanding capital balance and ceases in the month that the asset is placed into service. We also capitalize interest on our equity method investments which are devoting substantially all efforts to establishing a new business and have not yet begun planned principal operations. Capitalization ceases when the investee commences planned principal operations. The rates used to calculate capitalized interest are the weighted-average cost of debt, including the impact of interest rate swaps.

Asset Retirement Obligations - Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust our asset retirement obligation each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.

Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit-adjusted risk free interest rate, and accretes due to the passage of time based on the time value of money until the obligation is settled.

Goodwill and Intangible Assets - Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We perform an annual impairment test of goodwill at the reporting unit level during the third quarter, and update the test during interim periods when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of a reporting unit. We primarily use a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. A period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future goodwill and intangible assets impairment due to the potential impact on our operations and cash flows.

Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts, and related relationships. These intangible assets are amortized on a straight-line basis over the period of expected future benefit. Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period in which they become fully amortized.

Investments in Unconsolidated Affiliates - We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence.

We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value that is other than temporary, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.

Long-Lived Assets - We periodically evaluate whether the carrying value of long-lived assets, including intangible assets, has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:


•	significant adverse change in legal factors or business climate;


•	a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;


•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;


•	significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;


•	a significant adverse change in the market value of an asset; or


•	a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. A period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.

Unamortized Debt Discount and Expense - Premiums, discounts, and expenses incurred with the issuance of long-term debt are amortized over the term of the debt using the effective interest method. The premiums, discounts, and unamortized expenses are recorded on the consolidated balance sheets within the carrying amount of long-term debt.

Non-controlling Interest - Non-controlling interest represents any third-party or affiliate interest in non-wholly owned entities that we consolidate. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in our consolidated balance sheet amounts shown as non-controlling interest in equity. Distributions to and contributions from non-controlling interests represent cash payments to and cash contributions from, respectively, such third-party and affiliate investors.

Revenue Recognition - We generate the majority of our revenues from gathering, compressing, treating, processing, transporting, storing and selling of natural gas, and producing, fractionating, transporting, storing and selling NGLs and recovering and selling condensate. Once natural gas is produced from wells, producers then seek to deliver the natural gas and its components to end-use markets. We realize revenues either by selling the residue natural gas, NGLs and condensate, or by receiving fees.

We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the following arrangements:

•

Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas; and fractionating, storing and transporting NGLs. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced.

•

Percent-of-proceeds/index arrangements - Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and condensate based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in the producer retaining title to all or a portion of the residue natural gas and/or the NGLs, in lieu of us returning sales proceeds to the producer. Additionally, these arrangements may include fee-based components. Our revenues under percent-of-proceeds/index arrangements relate directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly with the price of NGLs and condensate.

•

Keep-whole and wellhead purchase arrangements - Under the terms of a keep-whole processing contract, natural gas is gathered from the producer for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a British thermal unit, or Btu, content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under the terms of a wellhead purchase contract, we purchase natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGLs and residue gas at market prices. Under these types of contracts, we are exposed to the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of residue natural gas, or frac spread. We benefit in periods when NGL prices are higher relative to natural gas prices when that frac spread exceeds our operating costs.

Our trading and marketing of natural gas and NGLs consists of physical purchases and sales, as well as positions in derivative instruments.

We recognize revenues for sales and services under the four revenue recognition criteria, as follows:


•	Persuasive evidence of an arrangement exists - Our customary practice is to enter into a written contract.


•	Delivery - Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.


•	The fee is fixed or determinable - We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

•

Collectability is reasonably assured - Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected.

We generally report revenues gross in the consolidated statements of operations, as we typically act as the principal in these transactions, take custody to the product, and incur the risks and rewards of ownership. New or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for commodity derivative activity net in the consolidated statements of operations as trading and marketing gains and losses. These activities include mark-to-market gains and losses on energy trading contracts and the settlement of financial and physical energy trading contracts.

Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as accounts receivable or accounts payable using current market prices or the weighted-average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash.

Purchases of natural gas and NGLs - Purchases of natural gas and NGLs represent physical purchases from suppliers.

Significant Customers - There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, 2016, 2015 and 2014. We had significant transactions with affiliates for the years ended December 31, 2016, 2015 and 2014. See Note 6, Agreements and Transactions with Related Parties and Affiliates.

Environmental Expenditures - Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.

Equity-Based Compensation — Liability classified share-based compensation cost is remeasured at each reporting date at fair value, based on the closing security price, and is recognized as expense over the requisite service period. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award.

Income Taxes - We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. We owned a corporation that filed its own federal and state corporate income tax returns, which we elected to convert to a limited liability company in 2016. Our income tax expense includes certain jurisdictions, including state, local, franchise and margin taxes of the master limited partnership and subsidiaries. We follow the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statements of operations, is proportionately included in the federal income tax returns of each partner.

Net Income or Loss per Limited Partner Unit - Basic and diluted net income or loss per limited partner unit, or LPU, is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per limited partner unit is computed based on the weighted average number of limited partner units, plus the effect of dilutive potential units outstanding during the period using the two-class method.

New Accounting Pronouncements	12 Months Ended
New Accounting Pronouncements	Dec. 31, 2016
Accounting Policies [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. This ASU is effective for interim and annual reporting periods beginning after December 15, 2017, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated statement of cash flows. FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases. This ASU is effective for interim and annual reporting periods beginning after December 15, 2018, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures. FASB ASU, 2015-16 “Business Combinations (Topic 805),” or ASU 2015-16 - In September 2015, the FASB issued ASU 2015-16, which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU is effective for interim and annual reporting periods beginning after December 15, 2016. The Partnership has adpoted the ASU and it did not have any impact on our consolidated results of operations, cash flows and financial position. FASB ASU 2015-02 “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” or ASU 2015-02 - In February 2015, the FASB issued ASU 2015-02, which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. This ASU was effective for annual reporting periods beginning after December 15, 2015. The retrospective adoption of this ASU has been implemented and did not have any impact on our consolidated results of operations, cash flows and financial position. FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations and amendments - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. We plan to adopt this ASU using the modified retrospective method. The initial cumulative effect will be recognized at the date of adoption. Our evaluation of ASU 2014-09 is ongoing and not complete. The FASB has issued and may issue in the future, interpretative guidance, which may cause our evaluation to change. Accordingly, at this time we cannot estimate the impact upon adoption.

- Definition

The entire disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Acquisitions	12 Months Ended
Acquisitions	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions	Acquisitions On January 1, 2017, DCP Midstream, LLC contributed to us: (i) its ownership interests in all of its subsidiaries owning operating assets, and (ii) $424 million of cash (together the “Contributions”). In consideration of the Partnership’s receipt of the Contributions, (i) the Partnership issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to the General Partner in a private placement and (ii) the Operating Partnership assumed $3,150 million of DCP Midstream, LLC’s debt. This represents a Transaction between entities under common control and a change in reporting entity. Pursuant to the Contribution Agreement, DCP Midstream, LLC agreed to cause the General Partner to enter into Amendment No. 3 (the “Third Amendment to the Partnership Agreement”) to the Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 1, 2006, as amended (the “Partnership Agreement”). On January 1, 2017, the General Partner, in its capacity as the general partner of the Partnership, entered into the Third Amendment to the Partnership Agreement. The Third Amendment to the Partnership Agreement includes terms that amend the Partnership Agreement to cause the incentive distributions payable to the holders of the Partnership’s incentive distribution rights with respect to the fiscal years 2017, 2018 and 2019 to, in certain circumstances, be reduced in an amount up to $100 million per fiscal year as necessary to provide that the distributable cash flow of the Partnership (as adjusted) during such year meets or exceeds the amount of distributions made by the Partnership (as adjusted) to the partners of the Partnership with respect to such year. On January 1, 2015, we entered into an agreement with an affiliate of Enterprise Products Partners L.P., or Enterprise, to acquire a 15% ownership interest in Panola Pipeline Company, LLC, or Panola. At closing, we paid $1 million for our interest in the joint venture. The total consideration of approximately $26 million included our proportionate share in construction costs for expansion of the existing Panola NGL pipeline. In accordance with the Panola joint venture agreement, earnings began to accrue on February 1, 2016. On March 31, 2014, DCP Midstream, LLC and its affiliates contributed to us: (i) a 33.33% membership interest in DCP Sand Hills Pipeline, LLC, which owns the Sand Hills pipeline; (ii) a 33.33% membership interest in DCP Southern Hills Pipeline, LLC, which owns the Southern Hills pipeline; and (iii) the remaining 20% interest in DCP SC Texas GP, or the Eagle Ford system. On March 28, 2014, we acquired from DCP Midstream, LLC and its affiliates (i) a 35 MMcf/d cryogenic natural gas processing plant located in Weld County, Colorado, or the Lucerne 1 plant; and (ii) a 200 MMcf/d cryogenic natural gas processing plant also located in Weld County, Colorado, or the Lucerne 2 plant. Together with the contribution of the interests in the Sand Hills and Southern Hills pipelines and the remaining 20% interest in the Eagle Ford system, the acquisition of the Lucerne 1 and 2 plants are collectively referred to hereafter as the March 2014 Transactions. Total consideration for the March 2014 Transactions at closing was $1,220 million, less customary working capital and other adjustments. $225 million of the consideration was funded by the issuance at closing of 2,098,674 of our common units to DCP Midstream, LLC, 1,399,116 of our common units to DCP LP Holdings, LLC, and 999,368 of our common units to DCP Midstream GP, LP. The remainder of the consideration was financed by a portion of the issuance of 14,375,000 common units to the public and the proceeds from our 5.60% 30-year Senior Notes and 2.70% five-year Senior Notes offering. The total consideration over the carrying value of the net assets of the Sand Hills and Southern Hills pipelines, the remaining 20% of the Eagle Ford system, and the Lucerne 1 and Lucerne 2 plants resulted in an excess purchase price of $178 million which was recorded as a decrease in limited partners' equity in the consolidated statement of changes in equity.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

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+ Details

Dispositions	12 Months Ended
Dispositions	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Dispositions	Dispositions In May 2016, we entered into a purchase and sale agreement with a third party to sell our 100% interest in our Northern Louisiana system, which primarily consisted of certain gas processing plants and gathering systems, for approximately $160 million, subject to customary purchase price adjustments. This transaction closed on July 1, 2016 and we recorded a gain of $41 million, net of goodwill, in the third quarter of 2016. In July 2015, we entered into a purchase and sale agreement with a third party to sell a gas processing plant and gathering system for approximately $120 million, subject to customary purchase price adjustments. This transaction closed on August 26, 2015, and we recognized a $59 million gain on sale in the consolidated statement of operations for the year ended December 31, 2015. In May 2015, we entered into purchase and sale agreements with WTG Benedum Joint Venture to sell our 33% interest in the Benedum gas processing plant and 100% interest in the Benedum gathering system, or Benedum, for approximately $21 million, subject to customary purchase price adjustments. This transaction closed on May 13, 2015, and we recognized a $27 million loss on sale, which included $2 million of goodwill, in the consolidated statement of operations for the year ended December 31, 2015. In January 2015, we entered into a purchase and sale agreement with Mustang Gas Products, LLC to sell our approximate 44% interest in the Dover-Hennessey gas processing plant and gathering system for approximately $29 million, subject to customary purchase price adjustments. This transaction closed on January 30, 2015, and we recognized a $10 million gain on sale in the consolidated statement of operations for the year ended December 31, 2015. In August 2014, we entered into a purchase and sale agreement with American Midstream, LLC to divest our two-thirds ownership interest in Main Pass Oil Gathering Company, or Main Pass, for total proceeds of approximately $14 million and selling costs of approximately $3 million. This transaction closed on August 11, 2014, and we recognized a $6 million loss on sale in the consolidated statements of operations for the year ended December 31, 2014.

- Definition

The entire disclosure related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

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+ Details

Agreements and Transactions with Affiliates

12 Months Ended

Dec. 31, 2016

Agreements and Transactions with Affiliates

DCP Midstream, LLC

Services Agreement and Other General and Administrative Charges

Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services and Employee Secondment Agreement (the “Services Agreement”) with DCP Services, LLC, an affiliate of DCP Midstream, LLC, which replaced the services agreement between the Partnership and DCP Midstream, LLC, dated February 14, 2013, as amended. Under the Services Agreement, we are required to reimburse DCP Midstream, LLC for costs, expenses, and expenditures incurred or payments made on our behalf for general and administrative functions including, but not limited to, legal, accounting, compliance, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, benefit plan maintenance and administration, credit, payroll, internal audit, taxes and engineering, as well as salaries and benefits of seconded employees, insurance coverage and claims, capital expenditures, maintenance and repair costs and taxes. There is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for costs, expenses and expenditures incurred or payments made on our behalf. For the years ended December 31, 2016, 2015 and 2014, the consolidated statements of operations include employee related costs that were charged by DCP Midstream, LLC of $206 million, $224 million and $225 million, respectively within operating and maintenance expense, and $197 million, $194 million and $184 million, respectively within general and administrative expense and restructuring costs.

Phillips 66 and its Affiliates

We sell a portion of our residue gas and NGLs to Phillips 66 and Chevron Phillips Chemical LLC, or CPChem. In addition, we purchase NGLs from CPChem. CPChem is owned 50% by Phillips 66, and is considered a related party. Approximately 27% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2016, the primary production commitment of which began a ratable wind down period in December 2014 and expires in January 2019. We anticipate continuing to purchase and sell commodities with Phillips 66 and its affiliates in the ordinary course of business.

Enbridge and its Affiliates including Spectra Energy Corp

We purchase NGLs from Enbridge and its affiliates. We anticipate continuing to purchase commodities and provide services to Enbridge and its affiliates in the ordinary course of business.

Unconsolidated Affiliates

We, along with other third party shippers, have entered into 15-year transportation agreements, with Sand Hills Pipeline, LLC, or Sand Hills, Southern Hills Pipeline, LLC, or Southern Hills, Front Range Pipeline LLC, or Front Range, and Texas Express Pipeline LLC, or Texas Express. Under the terms of these 15-year agreements, which commenced at each of the pipelines’ respective in-service dates and expire between 2028 and 2029, we have committed to transport minimum throughput volumes at rates defined in each of the pipelines’ respective tariffs.

Under the terms of their respective operating agreements, Sand Hills and Southern Hills are required to reimburse us for any direct costs or expenses (other than general and administration services) which we incur on behalf of Sand Hills and Southern Hills. Additionally, Sand Hills and Southern Hills each pay us an annual service fee of $5 million, for centralized corporate functions provided by us as operator of Sand Hills and Southern Hills, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. Except with respect to the annual service fee, there is no limit on the reimbursements Sand Hills and Southern Hills make to us under the respective operating agreements for other expenses and expenditures which we incur on behalf of Sand Hills or Southern Hills.

We also sell a portion of our residue gas and NGLs to, purchase natural gas and other NGL products from, and provide gathering and transportation services to other unconsolidated affiliates. We anticipate continuing to purchase and sell commodities and provide services to unconsolidated affiliates in the ordinary course of business.

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:



	Year Ended December 31,
	2016		2015		2014
	(Millions)
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	909	$	695	$	1,960
Purchases of natural gas and NGLs from affiliates	$	18	$	—	$	11
Operating and maintenance and general administrative expenses	$	2	$	4	$	3
Enbridge (including Spectra Energy Corp.):
Transportation, storage and processing to affiliates	$	—	$	—	$	14
Purchases of natural gas and NGLs from affiliates	$	33	$	50	$	88
Operating and maintenance and general administrative expenses	$	4	$	6	$	10
Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates	$	43	$	70	$	70
Transportation, storage and processing	$	5	$	3	$	12
Purchases of natural gas and NGLs from affiliates	$	432	$	368	$	366

We had balances with affiliates as follows:



	December 31,
	2016		2015
	(Millions)
Phillips 66 (including its affiliates):
Accounts receivable	$	115	$	54
Accounts payable	$	4	$	3
Other assets	$	2	$	1
Enbridge (including Spectra Energy Corp.):
Accounts receivable	$	1	$	—
Accounts payable	$	3	$	4
Other assets	$	1	$	1
Other liabilities	$	1	$	—
Unconsolidated affiliates:
Accounts receivable	$	18	$	21
Accounts payable	$	41	$	33
Other assets	$	5	$	31

Inventories

12 Months Ended

Dec. 31, 2016

Inventory Disclosure [Abstract]

Inventories

Inventories were as follows:



	December 31,
	2016		2015
	(Millions)
Natural gas	$	28	$	29
NGLs	44		22
Total inventories	$	72	$	51

We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases of natural gas and NGLs in the consolidated statements of operations. We recognized $3 million, $8 million and $24 million in lower of cost or market adjustments during the years ended December 31, 2016, 2015, and 2014, respectively.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment by classification were as follows:



		December 31,
	Depreciable Life	2016			2015
		(Millions)
Gathering and transmission systems	20 — 50 Years	$	8,560		$	8,815
Processing, storage, and terminal facilities	35 — 60 Years	5,134			5,102
Other	3 — 30 Years	502			485
Construction work in progress		171			196
Property, plant and equipment		14,367			14,598
Accumulated depreciation		(5,298		)	(5,170		)
Property, plant and equipment, net		$	9,069		$	9,428

Interest capitalized on construction projects was less than $1 million for the year ended December 31, 2016. Interest capitalized on construction projects for the years ended December 31, 2015 and 2014 was $32 million and $34 million, respectively.

Depreciation expense was $366 million, $358 million and $327 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Asset Retirement Obligations

We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.

The following table summarizes changes in the asset retirement obligations included in our balance sheets:



	December 31,
	2016 (a)			2015 (a)
	(millions)
Balance, beginning of period	$	120		$	117
Accretion expense	7			7
Revisions in estimated cash flows	(3		)	(4		)
Balance, end of period	$	124		$	120

(a) Asset retirement obligations are included in other long-term liabilities in the consolidated balance sheets. Accretion expense is recorded within operating and maintenance expense in our consolidated statement of operations. Accretion expense for the year ended December 31, 2014 was $6 million.

Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets

We performed our annual goodwill assessment during the third quarter of 2016 at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. As a result of our assessment, we concluded that the fair value of goodwill substantially exceeded its carrying value and that the entire amount of goodwill disclosed on the consolidated balance sheet is recoverable. We primarily used a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows, including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information (including forecasted volumes and commodity prices), as well as historical and other factors. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.

During the second quarter of 2015, we recognized a goodwill impairment based on our best estimate of the impairment resulting from the performance of the hypothetical purchase price allocation which totaled $378 million for our Mid-continent and Permian reporting units and $49 million for our Collbran, Michigan, and Southeast Texas reporting units. We completed the hypothetical purchase price allocation in the third quarter of 2015 and after completing the analysis, there was no remaining fair value to assign to the goodwill of the Collbran reporting unit. As a result, we recorded an additional impairment of $33 million in the third quarter of 2015.

We performed our annual goodwill assessment during the quarter ended September 30, 2015. We concluded that the fair value of goodwill of our remaining reporting units exceeded their carrying value, and the entire amount of goodwill disclosed on the consolidated balance sheet associated with these remaining reporting units is recoverable, therefore, no other goodwill impairments were identified or recorded for the remaining reporting units as a result of our annual goodwill assessment.

The change in carrying amount of goodwill in each of our reportable segments was as follows:



	Year Ended December 31,
	2016								2015
	(Millions)
	Gathering and Processing			Logistics and Marketing		Total			Gathering and Processing			Logistics and Marketing		Total
Balance, beginning of period	$	170		$	72	$	242		$	632		$	72	$	704
Impairment	—			—		—			(460		)	—		(460		)
Dispositions	$	(6	)	$	—	$	(6	)	$	(2	)	$	—	$	(2	)
Balance, end of period	$	164		$	72	$	236		$	170		$	72	$	242

Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts and related relationships. The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows:



	December 31,
	2016			2015
	(Millions)
Gross carrying amount	$	410		$	410
Accumulated amortization	(151		)	(139		)
Accumulated impairment	(122		)	(122		)
Intangible assets, net	$	137		$	149

We recorded amortization expense of $12 million, $19 million and $21 million for the years ended December 31, 2016, 2015, and 2014, respectively. As of December 31, 2016, the remaining amortization periods ranged from approximately 2 years to 19 years, with a weighted-average remaining period of approximately 14 years.

Estimated future amortization for these intangible assets is as follows:



Estimated Future Amortization
(Millions)
2017	$	11
2018	11
2019	11
2020	11
2021	11
Thereafter	82
Total	$	137

- Definition

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

+ References + Details

Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Affiliates

The following table summarizes our investments in unconsolidated affiliates:



		Carrying Value as of
	Percentage Ownership	December 31, 2016		December 31, 2015
		(Millions)
DCP Sand Hills Pipeline, LLC	66.67%	$	1,507	$	1,492
DCP Southern Hills Pipeline, LLC	66.67%	754		764
Discovery Producer Services LLC	40.00%	385		405
Front Range Pipeline LLC	33.33%	165		170
Texas Express Pipeline LLC	10.00%	93		96
Panola Pipeline Company, LLC	15.00%	25		19
Mont Belvieu Enterprise Fractionator	12.50%	23		25
Mont Belvieu 1 Fractionator	20.00%	10		11
Other	Various	7		10
Total investments in unconsolidated affiliates		$	2,969	$	2,992

There was an excess of the carrying amount of the investment over the underlying equity of Sand Hills of $662 million and $677 million as of December 31, 2016 and 2015, respectively, which is associated with and being amortized over the life of the underlying long-lived assets of Sand Hills.

There was an excess of the carrying amount of the investment over the underlying equity of Southern Hills of $148 million and $152 million as of December 31, 2016 and 2015, respectively, which is associated with, and being amortized over the life of, the underlying long-lived assets of Southern Hills.

There was a deficit between the carrying amount of the investment and the underlying equity of Discovery Producer Services, LLC, or Discovery, of $20 million and $24 million as of December 31, 2016 and 2015, respectively, which is associated with, and is being amortized over the life of, the underlying long-lived assets of Discovery.

There was an excess of the carrying amount of the investment over the underlying equity of Front Range of $5 million at both December 31, 2016 and 2015, which is associated with, and is being amortized over the life of, the underlying long-lived assets of Front Range.

There was an excess of the carrying amount of the investment over the underlying equity of Texas Express of $3 million at both December 31, 2016 and 2015, which is associated with, and is being amortized over the life of, the underlying long-lived assets of Texas Express.

There was a deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu I Fractionation Facility, or Mont Belvieu I, of $2 million and $3 million as of December 31, 2016 and 2015, respectively, which is associated with, and is being amortized over the life of the underlying long-lived assets of Mont Belvieu I.

Earnings from investments in unconsolidated affiliates were as follows:



		Year Ended December 31,
		2016		2015		2014
	(Millions)
DCP Sand Hills Pipeline, LLC		$	110	$	63	$	26
Discovery Producer Services LLC		73		54		7
DCP Southern Hills Pipeline, LLC		44		18		15
Front Range Pipeline LLC		19		17		2
Mont Belvieu Enterprise Fractionator		16		15		17
Mont Belvieu 1 Fractionator		9		9		12
Texas Express Pipeline LLC		9		8		3
Other		2		—		—
Total earnings from unconsolidated affiliates		$	282	$	184	$	82

The following tables summarize the combined financial information of our investments in unconsolidated affiliates:



		Year Ended December 31,
		2016		2015		2014
	(Millions)
Statements of operations (a):
Operating revenue		$	1,311	$	1,142	$	859
Operating expenses		$	539	$	541	$	503
Net income		$	768	$	600	$	354



	December 31,
	2016			2015
	(Millions)
Balance sheets (a):
Current assets	$	232		$	240
Long-term assets	5,274			5,224
Current liabilities	(156		)	(167		)
Long-term liabilities	(205		)	(230		)
Net assets	$	5,145		$	5,067

(a) In accordance with the Panola Pipeline Company, LLC, or Panola, joint venture agreement, earnings

began to accrue to the Partnership’s interest on February 1, 2016. Accordingly, activity related to Panola

is included in the above tables as of and for the year ended December 31, 2016.

Fair Value Measurement

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurement

Determination of Fair Value

Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, and/or the liquidity of the market.

•

Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.

•

Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.

•

Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 13 - Risk Management and Hedging Activities.

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.


•	Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.


•	Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.


•	Level 3 — inputs are unobservable and considered significant to the fair value measurement.

A financial instrument’s categorization within the hierarchy is based upon the level of judgment involved in the most significant input in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.

Commodity Derivative Assets and Liabilities

We enter into a variety of derivative financial instruments, which may include exchange traded instruments (such as New York Mercantile Exchange, or NYMEX, crude oil or natural gas futures) or over-the-counter, or OTC, instruments (such as natural gas contracts, crude oil or NGL swaps). The exchange traded instruments are generally executed with a highly rated broker dealer serving as the clearinghouse for individual transactions.

Our activities expose us to varying degrees of commodity price risk. To mitigate a portion of this risk and to manage commodity price risk related primarily to owned natural gas storage and pipeline assets, we engage in natural gas asset based trading and marketing, and we may enter into natural gas and crude oil derivatives to lock in a specific margin when market conditions are favorable. A portion of this may be accomplished through the use of exchange traded derivative contracts. Such instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange traded instrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy we may enter into exchange traded derivative positions with a significant time horizon to maturity. Although such instruments are exchange traded, market prices may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.

We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third-party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.

Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.

Interest Rate Derivative Assets and Liabilities

We may use interest rate swap agreements as part of our overall capital strategy. These instruments would effectively exchange a portion of our existing floating rate debt for fixed-rate debt. Historically, our swaps have been generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of our interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.

Benefits

We offer certain eligible DCP Midstream, LLC executives the opportunity to participate in our DCP Midstream LP’s Non-Qualified Executive Deferred Compensation Plan, or the EDC Plan. All amounts contributed to and earned by the EDC Plan’s investments are held in a trust account, which is managed by a third-party service provider. The trust account is invested in short-term money market securities and mutual funds. These investments are recorded at fair value, with any changes in fair value being recorded as a gain or loss in our consolidated statements of operations. Given that the value of the short-term money market securities and mutual funds are publicly traded and for which market prices are readily available, these investments are classified within Level 1.

Nonfinancial Assets and Liabilities

We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, and other long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

There were no assets measured at fair value on a non-recurring basis as of December 31, 2016. The following table presents the carrying value of assets measured at fair value on a non-recurring basis, by consolidated balance sheet caption and by valuation hierarchy, as of December 31, 2015:



	Fair Value Measurements Using
	Net Carrying Value		Level 1		Level 2		Level 3		Asset Impairments
	(millions)
December 31, 2015:
Goodwill	$	—	$	—	$	—	$	—	$	460
Property, plant and equipment	87		—		—		87		302
Intangible assets	36		—		—		36		122
Other assets	50		—		—		50		28
Total non-recurring assets measured at fair value	$	173	$	—	$	—	$	173	$	912

The following table presents the financial instruments carried at fair value as of December 31, 2016 and 2015, by consolidated balance sheet caption and by valuation hierarchy, as described above:



	December 31, 2016												December 31, 2015
	Level 1			Level 2			Level 3			Total Carrying Value			Level 1			Level 2			Level 3			Total Carrying Value
	(Millions)
Current assets:
Commodity derivatives (a)	$	5		$	28		$	9		$	42		$	23		$	98		$	35		$	156
Short-term investments (b)	$	—		$	—		$	—		$	—		$	2		$	—		$	—		$	2
Long-term assets:
Commodity derivatives (c)	$	—		$	—		$	5		$	5		$	3		$	12		$	4		$	19
Mutual funds (d)	$	—		$	—		$	—		$	—		$	8		$	—		$	—		$	8
Current liabilities:
Commodity derivatives (e)	$	(11	)	$	(57	)	$	(23	)	$	(91	)	$	(16	)	$	(30	)	$	(23	)	$	(69	)
Long-term liabilities:
Commodity derivatives (f)	$	(1	)	$	—		$	—		$	(1	)	$	(1	)	$	(5	)	$	(6	)	$	(12	)


(a)	Included in current unrealized gains on derivative instruments in our consolidated balance sheets.


(b)	Includes short-term money market securities included in cash and cash equivalents in our consolidated balance sheets.


(c)	Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.


(d)	Included in other long-term assets in our consolidated balance sheets.


(e)	Included in current unrealized losses on derivative instruments in our consolidated balance sheets.


(f)	Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets.

Changes in Levels 1 and 2 Fair Value Measurements

The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period. Amounts transferred in and out of Level 1 and Level 2 are reflected at fair value as of the end of the period. During the years ended December 31, 2016 and 2015, there were no transfers between Level 1 and Level 2 of the fair value hierarchy.

Changes in Level 3 Fair Value Measurements

The tables below illustrate a rollforward of the amounts included in our consolidated balance sheets for derivative financial instruments that we have classified within Level 3. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into/out of Level 3” captions.

We manage our overall risk at the portfolio level and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the table below, the gains or losses in the table do not reflect the effect of our total risk management activities.



	Commodity Derivative Instruments
	Current Assets			Long- Term Assets		Current Liabilities			Long- Term Liabilities
	(Millions)
Year ended December 31, 2016 (a):
Beginning balance	$	35		$	4	$	(23	)	$	(6	)
Net unrealized gains (losses) included in earnings (b)	3			1		(15		)	6
Settlements	(29		)	—		15			—
Ending balance	$	9		$	5	$	(23	)	$	—
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	9		$	3	$	(23	)	$	6
Year ended December 31, 2015 (a):
Beginning balance	$	23		$	3	$	(45	)	$	(12	)
Net unrealized gains (losses) included in earnings (b)	(82		)	1		(29		)	6
Transfers out of Level 3 (c)	—			—		1			—
Settlements	(25		)	—		50			—
Novation (d)	119			—		—			—
Ending balance	$	35		$	4	$	(23	)	$	(6	)
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	(84	)	$	1	$	(23	)	$	4


(a)	There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the years ended December 31, 2016 and 2015.


(b)	Represents the amount of total gains or losses for the period, included in trading and marketing gains or losses, net, in our consolidated statements of operations.


(c)	Amounts transferred out of Level 3 are reflected at fair value as of the end of the period.


(d)	Represents the March 2015 novation of certain fixed price commodity derivatives.

Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable Inputs

We utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in these contracts.



	December 31, 2016
Product Group	Fair Value			Forward Curve Range
	(Millions)
Assets
NGLs	$	14		$0.25-$1.20	Per gallon
Liabilities
NGLs	$	(23	)	$0.25-$1.23	Per gallon

Estimated Fair Value of Financial Instruments

Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected relationship with quoted market prices.

The fair value of our interest rate swaps, if any, and commodity non-trading derivatives is based on prices supported by quoted market prices and other external sources and prices based on models and other valuation methods. The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, if any, our NGL and crude oil swaps and our NYMEX positions in natural gas. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from a third party pricing service and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which OTC broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate. The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the specific market point.

We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

The fair value of accounts receivable, accounts payable and short-term borrowings are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value.

We determine the fair value of our fixed-rate senior notes and junior subordinated notes based on quotes obtained from bond dealers. We determine the fair value of borrowings under our revolving credit facility based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit facilities available in the marketplace. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of December 31, 2016 and 2015, the carrying value and fair value of our total debt, includiing current maturities, were as follows:

December 31, 2016

December 31, 2015

Carrying Value (a)

Fair Value

Carrying Value (a)

Fair Value

(Millions)

Total debt

5,430

5,395

5,704

4,754

(a) Excludes unamortized issuance costs.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Debt

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Debt



	December 31,
	2016			2015
	(Millions)
Senior notes:
Issued November, 2012, interest at 2.500% payable semi-annually, due December, 2017	500			500
Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a)	450			450
Issued March, 2014, interest at 2.700% payable semi-annually, due April, 2019	325			325
Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a)	600			600
Issued September 2011, interest at 4.750% payable semiannually, due September 2021	500			500
Issued March, 2012, interest at 4.950% payable semi-annually, due April, 2022	350			350
Issued March, 2013, interest at 3.875% payable semi-annually, due March, 2023	500			500
Issued August 2000, interest at 8.125% payable semiannually, due August 2030 (a)	300			300
Issued October 2006, interest at 6.450% payable semiannually, due November 2036	300			300
Issued September 2007, interest at 6.750% payable semiannually, due September 2037	450			450
Issued March, 2014, interest at 5.600% payable semi-annually, due April, 2044	400			400
Junior subordinated notes:
Issued May 2013, interest at 5.850% payable semiannually, due May 2043	550			550
Credit facilities with financial institutions:
Revolving credit agreement terminated December, 2016, weighted average interest rate of 2.930% at December 31, 2015	—			96
Revolving credit agreement, weighted-average variable interest rate of 2.014% and 1.572%, as of December 31, 2016 and December 31, 2015, respectively, due May 2019	195			375
Fair value adjustments related to interest rate swap fair value hedges (a)	24			26
Unamortized issuance costs	(23		)	(35		)
Unamortized discount	(14		)	(18		)
Total debt	5,407			5,669
Current maturities of long-term debt	500			—
Total long-term debt	$	4,907		$	5,669

(a) The swaps associated with this debt were previously terminated. The remaining long-term fair value of approximately $24 million related to the swaps is being amortized as a reduction to interest expense through 2019, 2020 and 2030, the original maturity dates of the debt.

Credit Facilities with Financial Institutions

In May 2016, we entered into a second amendment of the DCP Midstream Amended and Restated Revolving Credit Agreement (the DCP Midstream Amended and Restated Credit Agreement), which extended the maturity date from March 2017 to May 2019 and reduced the total borrowing capacity from $1.8 billion to $700 million. The DCP Midstream Amended and Restated Revolving Credit Agreement was terminated on December 30, 2016. In conjunction with the termination of the DCP Midstream Amended and Restated Revolving Credit Agreement, $10 million of unamortized issuance costs were included in interest expense.

In March 2015, we entered into a first amendment of the DCP Midstream Amended and Restated Revolving Credit Agreement, which reduced the total borrowing capacity of the facility from $2.0 billion to $1.8 billion and revised the maturity date of the facility from May 2019 to March 2017. None of our physical assets were pledged as collateral for borrowings under this facility. The DCP Midstream Amended and Restated Revolving Credit Agreement was used to support our capital expansion program, for working capital requirements and other general corporate purposes, including acquisitions, as well as for letters of credit.

We have a $1.25 billion senior unsecured revolving credit agreement that matures on May 1, 2019, or the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions.

Our cost of borrowing under the Amended and Restated Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Amended and Restated Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.45% based on our current credit rating; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate, plus 0.50% or the LIBOR Market Index rate, plus 1%, plus (b) an applicable margin of 0.45% based on our current credit rating. The Amended and Restated Credit Agreement incurs an annual facility fee of 0.3% based on our current credit rating. This fee is paid on drawn and undrawn portions of the $1.25 billion Amended and Restated Credit Agreement.

As of December 31, 2016, we had unused borrowing capacity of $1,031 million, net of $24 million of letters of credit, under the Amended and Restated Credit Agreement. The financial covenants set forth in the Credit Agreement limit the Partnerships ability to incur incremental debt by $970 million as of December 31, 2016. Our borrowing capacity may be limited by financial covenants set forth in the Amended and Restated Credit Agreement. Except in the case of a default, amounts borrowed under our Amended and Restated Credit Agreement will not become due prior to the May 1, 2019 maturity date.

The Amended and Restated Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Amended and Restated Credit Agreement) of not more than 5.0 to 1.0, and following the consummation of qualifying acquisitions, not more than 5.5 to 1.0, on a temporary basis for three consecutive quarters, including the quarter in which such acquisition is consummated.

Senior Notes and Junior Subordinated Notes

Our senior notes and junior subordinated notes, collectively referred to as our debt securities, mature and become payable on the respective due dates, and are not subject to any sinking fund or mandatory redemption provisions. The senior notes are senior unsecured obligations that are guaranteed by the Partnership and rank equally in a right of payment with our other senior unsecured indebtedness, including indebtedness under our credit agreement, and the junior subordinated notes are unsecured and rank subordinate in right of payment to all of our existing and future senior indebtedness. The debt securities include an optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time for a premium. Additionally, we may defer the payment of all or part of the interest on the junior subordinated notes for one or more periods up to five consecutive years. The underwriters’ fees and related expenses are recorded in our consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes.

The future maturities of debt in the year indicated are as follows:



	Debt Maturities
	(Millions)
2017	$	500
2018	—
2019	970
2020	600
2021	500
Thereafter	2,850
	5,420
Fair value adjustments related to interest rate swap fair value hedges	24
Unamortized issuance costs	(23		)
Unamortized discount	(14		)
Total	$	5,407

Risk Management and Hedging Activities

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management and Hedging Activities

Risk Management and Hedging Activities, Credit Risk and Financial Instruments

Our day-to-day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with either physical or financial transactions. We have established a comprehensive risk management policy, or Risk Management Policy, and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. Our Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following describes each of the risks that we manage.

Commodity Price Risk

Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. The risks, strategies and instruments used to mitigate such risks, as well as the method of accounting are discussed and summarized below.

Natural Gas Asset Based Trading and Marketing

Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.

A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

Commodity Cash Flow Hedges

In order for our natural gas storage facility to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns into operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase base gas, the deferred losses or gains would remain in accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of December 31, 2016.

Commodity Cash Flow Protection Activities

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We may enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. Our derivative financial instruments used to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices extend through the first quarter of 2018. The commodity derivative instruments used for our hedging programs are a combination of direct NGL product, crude oil and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we may use crude oil swaps to mitigate a portion of the commodity price risk exposure for NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The relationship of NGLs to crude oil continues to be lower than historical relationships. When our crude oil swaps become short-term in nature, certain crude oil derivatives may be converted to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange floating price risk for a fixed price. The type of instrument used to mitigate a portion of the risk may vary depending on our risk management objectives. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected in the current period within our consolidated statements of operations as trading and marketing (losses) gains, net.

NGL Proprietary Trading

Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities through the use of fixed forward sales and purchases, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and these operations may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. These physical and financial instruments are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statements of operations.

We employ established risk limits, policies and procedures to manage risks associated with our natural gas asset based trading and marketing and NGL proprietary trading.

Interest Rate Risk

We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates.

We previously had interest rate cash flow hedges and fair value hedges in place that were terminated. As the underlying transactions impact earnings, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to interest expense, net from 2022 through 2030 and the remaining net loss included in long-term debt relative to these fair value hedges will be reclassified to interest expense, net from 2019 through 2030, the original maturity dates of the debt.

Credit Risk

Our principal customers range from large, natural gas marketers to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 27% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2016. This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use various master agreements that include language giving us the right to request collateral to mitigate credit exposure. The collateral language provides for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral language also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our master agreements and our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form.

Contingent Credit Features

Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.

We have International Swaps and Derivatives Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below.


•	If we were to have an effective event of default under our Amended and Restated Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.


•	Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liability position, when our credit rating is below investment grade.

•

Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under other credit arrangements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Amended and Restated Credit Agreement. As of December 31, 2016, we were not a party to any agreements that would trigger the cross-default provisions.

Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features.

Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net liability position. As of December 31, 2016, we had less than $1 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position. If we were required to net settle our position with an individual counterparty, due to a credit-risk related event, our ISDA contracts may permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of December 31, 2016, we were not required to post additional collateral. Although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of December 31, 2016, the net liability position would be offset by contracts in a net asset position.

Collateral

As of December 31, 2016, we had cash deposits of $71 million, included in current assets in our consolidated balance sheet, and letters of credit of $13 million with counterparties to secure our obligations to provide future services or to perform under financial contracts. Additionally, as of December 31, 2016, we held cash of $5 million, included in other current liabilities in our consolidated balance sheet, related to cash postings by third parties and letters of credit of $38 million from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateral requirements.

Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.

Offsetting

Certain of our derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to settle multiple positions with an individual counterparty through a single net payment. Each of our individual derivative instruments are presented on a gross basis on the consolidated balance sheets, regardless of our ability to net settle our positions. Instruments that are governed by agreements that include net settle provisions allow final settlement, when presented with a termination event, of outstanding amounts by extinguishing the mutual debts owed between the parties in exchange for a net amount due. We have trade receivables and payables associated with derivative instruments, subject to master netting or similar agreements, which are not included in the table below. The following summarizes the gross and net amounts of our derivative instruments:



	December 31, 2016								December 31, 2015
	Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)		Net Amount			Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount
	(Millions)
Assets:
Commodity derivatives	$	47		$	—	$	47		$	175		$	(1	)	$	174
Liabilities:
Commodity derivatives	$	(92	)	$	—	$	(92	)	$	(81	)	$	—		$	(81	)

(a)Included in other current liabilities in our consolidated balance sheets.

Summarized Derivative Information

The fair value of our derivative instruments that are designated as hedging instruments, those that are marked to market each period, and the location of each within our consolidated balance sheets, by major category, is summarized below:



Balance sheet line item	December 31, 2016		December 31, 2015		Balance sheet line item	December 31, 2016			December 31, 2015
	(Millions)					(Millions)
Derivative assets not designated as hedging instruments:					Derivative liabilities not designated as hedging instruments:
Commodity derivatives:					Commodity derivatives:
Unrealized gains on derivative instruments — current	$	42	$	156	Unrealized losses on derivative instruments — current	$	(91	)	$	(69	)
Unrealized gains on derivative instruments — long-term	5		19		Unrealized losses on derivative instruments — long-term	(1		)	(12		)
Total	$	47	$	175	Total	$	(92	)	$	(81	)

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2016:



	Interest Rate Derivatives			Commodity Derivatives			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(3	)	$	(6	)	$	1	$	(8	)
Net deferred (losses) gains in AOCI (ending balance)	$	(3	)	$	(6	)	$	1	$	(8	)


(a)	Relates to Discovery, an unconsolidated affiliate.

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2015:



	Interest Rate Cash Flow Hedges			Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(4	)	$	(6	)	$	1	$	(9	)
Losses reclassified from AOCI to earnings — effective portion (b)	1			—			—		1
Net deferred losses in AOCI (ending balance)	$	(3	)	$	(6	)	$	1	$	(8	)


(a)	Relates to Discovery, an unconsolidated affiliate.


(b)	Included in interest expense in our consolidated statements of operations.

For the years ended December 31, 2016 and 2015, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in trading and marketing gains or losses, net or interest expense in our consolidated statements of operations. For the years ended December 31, 2016 and 2015, no derivative losses were reclassified from AOCI to trading and marketing gains or losses, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

Changes in the value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the consolidated statements of operations. The following summarizes these amounts and the location within the consolidated statements of operations that such amounts are reflected:



		Year Ended December 31,
Derivatives: Statements of Operations Line Item		2016			2015		2014
	(Millions)
Realized gains		$	116		$	73	$	45
Unrealized (losses) gains		(139		)	46		43
Trading and marketing (losses) gains, net		$	(23	)	$	119	$	88

We do not have any derivative financial instruments that qualify as a hedge of a net investment.

The following tables represent, by commodity type, our net long or short derivative positions, as well as the number of outstanding contracts that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the table below.



	December 31, 2016
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net (Short) Long Position (Bbls)		Net Long Position (MMBtu)
2017	(1,470,000	)	(44,981,850	)	(22,225,821	)	6,510,000
2018	(251,000	)	—		144,805		912,500
2019	(40,000	)	—		(2,203	)	—
2020	(50,000)		—		240,000		—



	December 31, 2015
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net (Short) Long Position (Bbls)		Net Long Position (MMBtu)
2016	(1,566,672	)	(25,059,414	)	(23,575,094	)	2,207,500
2017	(237,000	)	(7,387,500	)	(2,082,157	)	4,050,000
2018	—		—		120,000		—

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6441202&loc=d3e80720-113993

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624171-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41620-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624163-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
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-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579240-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624177-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80784-113994

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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+ Details

Partnership Equity and Distributions

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Partnership Equity and Distributions

During the year ended December 31, 2016, we issued no common units pursuant to our 2014 equity distribution agreement. As of December 31, 2016, approximately $349 million of common units remained available for sale pursuant to our 2014 equity distribution agreement.

During the year ended December 31, 2015, we issued 788,033 common units pursuant to our 2014 equity distribution agreement and received proceeds of $31 million, net of commissions and offering costs of less than $1 million.

In June 2014, we filed a shelf registration statement on Form S-3 with the SEC with a maximum offering price of $500 million, which became effective on July 11, 2014. The shelf registration statement allows us to issue additional common units. In September 2014, we entered into an equity distribution agreement, or the 2014 equity distribution agreement, with a group of financial institutions as sales agents. The 2014 equity distribution agreement provides for the offer and sale from time to time, through our sales agents, of common units having an aggregate offering amount of up to $500 million. During the year ended December 31, 2014, we issued 2,256,066 of our common units pursuant to the 2014 equity distribution agreement and received proceeds of $119 million, net of commissions and accrued offering costs of $1 million, which were used to finance growth opportunities and for general partnership purposes.

In March 2014, we issued 14,375,000 common units to the public at $48.90 per unit. We received proceeds of $677 million, net of offering costs.

In March 2014, we issued 4,497,158 common units to DCP Midstream, LLC as partial consideration for certain transactions that closed in March 2014.

Definition of Available Cash — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash, as defined in the partnership agreement, to unitholders of record on the applicable record date, as determined by our general partner. Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:


•	less the amount of cash reserves established by the general partner to:

•provide for the proper conduct of our business;

•comply with applicable law, any of our debt instruments or other agreements; and


•	provide funds for distributions to the unitholders and to our general partner for any one or more of the next four quarters;


•	plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter.

General Partner Interest and Incentive Distribution Rights - The general partner is entitled to a percentage of all quarterly distributions equal to its general partner interest of approximately 0.3% and limited partner interest of approximately 1.7% as of December 31, 2016. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest.

The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level. The general partner’s incentive distribution rights were not reduced as a result of our common unit issuances, and will not be reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest. Please read the Distributions of Available Cash sections below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

Distributions of Available Cash - Our partnership agreement, after adjustment for the general partner’s relative ownership level, requires that we make distributions of Available Cash from operating surplus for any quarter in the following manner:


•	first, to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter;


•	second, 13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter;


•	third, 23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter; and


•	thereafter, 48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders.

The following table presents our cash distributions paid in 2016, 2015 and 2014:



Payment Date	Per Unit Distribution		Total Cash Distribution
	(Millions)
November 14, 2016	$	0.7800	$	120
August 12, 2016	$	0.7800	$	121
May 13, 2016	$	0.7800	$	121
February 12, 2016	$	0.7800	$	121
November 13, 2015	$	0.7800	$	120
August 14, 2015	$	0.7800	$	121
May 15, 2015	$	0.7800	$	121
February 13, 2015	$	0.7800	$	120
November 14, 2014	$	0.7700	$	117
August 14, 2014	$	0.7575	$	111
May 15, 2014	$	0.7450	$	106
February 14, 2014	$	0.7325	$	86

Equity-Based Compensation

12 Months Ended

Dec. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

Equity-Based Compensation

On April 28, 2016, the unitholders of the Partnership approved the 2016 Long-Term Incentive Plan (the “2016 LTIP”), which replaced the 2005 Long-Term Incentive Plan that expired pursuant to its terms at the end of 2015 (the “2005 LTIP” and, together with the 2012 LTIP and the 2016 LTIP, the “LTIP”). Any outstanding awards under the 2005 LTIP will remain outstanding and settle according to the terms of such grant. The 2016 plan authorizes up to 900,000 common units to be available for issuance under awards to employees, officers, and non-employee directors of the General Partner and its affiliates. Awards under the 2016 LTIP may include unit options, phantom units, restricted units, distribution equivalent rights, unit bonuses, common unit awards, and performance awards. The 2016 LTIP will expire on the earlier of the date it is terminated by the board of directors of the General Partner or the date that all common units available under the plan have been paid or issued.

On November 28, 2005, the board of directors of our General Partner adopted the 2005 LTIP, for employees, consultants and directors of our General Partner and its affiliates who perform services for us. The 2005 LTIP provides for the grant of limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of dividend equivalent rights, or DERs. The 2005 LTIP phantom units consist of a notional unit based on the value of the Partnership's common units. Subject to adjustment for certain events, an aggregate of 850,000 LPUs may be issued and delivered pursuant to awards under the 2005 LTIP. Awards that are canceled or forfeited, or are withheld to satisfy the General Partner’s tax withholding obligations, are available for delivery pursuant to other awards. On February 15, 2012, the board of directors of our General Partner adopted the 2012 LTIP (the "2012 LTIP") for employees, consultants and directors of our General Partner and its affiliates who perform services for us. The 2012 LTIP provided for the grant of phantom units and DERs. The 2012 LTIP phantom units consist of a notional unit based on the value of common units or shares of Phillips 66 and Enbridge. The LTIPs were administered by the compensation committee of the General Partner’s board of directors through 2012, and by the General Partner’s board of directors beginning in 2013. All awards under the LTIPs are subject to cliff vesting.

Under DCP Midstream, LLC's Long-Term Incentive Plan ("DCP Midstream LTIP"), awards may be granted to key employees. The DCP Midstream LTIP provides for the grant of Strategic Performance Units ("SPUs") and Phantom Units. The SPUs and Phantom Units consist of a notional unit based on the value of common shares or units of Phillips 66, Enbridge and the Partnership. Each award provides for the grant of dividend or distribution equivalent rights, or DERs. The DCP Midstream LTIP is administered by the compensation committee of DCP Midstream, LLC's board of directors. All awards are subject to cliff vesting.

Since we have the intent and ability to settle certain awards within our control in units, we classify them as equity awards based on their fair value. The fair value of our equity awards is determined based on the closing price of our common units on the grant date. Compensation expense on equity awards is recognized ratably over each vesting period. We account for other awards which are subject to settlement in cash, including DERs, as liability awards. Compensation expense on these awards is recognized ratably over each vesting period, and will be re-measured each reporting period for all awards outstanding until the units are vested. The fair value of all liability awards is determined based on the closing price of our common units at each measurement date.

Equity-based compensation expense was $18 million, $8 million and $14 million for the years ended December 31, 2016, 2015 and 2014, respectively.

The following table presents the fair value of unvested unit-based awards related to the strategic performance units and phantom units:



	Vesting Period (years)	Unrecognized Compensation Expense at December 31, 2016 (millions)		Estimated Forfeiture Rate	Weighted-Average Remaining Vesting (years)
DCP Midstream LTIP:
Strategic Performance Units (SPUs)	3	$	6	0%-11%	2
Phantom Units	1-3	$	5	0%-11%	2

Strategic Performance Units - The number of SPUs that will ultimately vest range in value of up to 200% of the outstanding SPUs, depending on the achievement of specified performance targets over a three year period. The final performance payout is determined by the compensation committee of our board of directors. The DERs are paid in cash at the end of the performance period. The following tables presents information related to SPUs:



	Units		Grant Date Weighted-Average Price Per Unit		Measurement Date Weighted-Average Price Per Unit
Outstanding at January 1, 2014	230,900		$	39.30
Granted	116,790		$	54.05
Forfeited	(13,828	)	$	40.75
Vested (a)	(114,499	)	$	37.72
Outstanding at December 31, 2014	219,363		$	47.89
Granted	111,930		$	43.25
Forfeited	(29,283	)	$	48.02
Vested (b)	(93,551	)	$	41.02
Outstanding at December 31, 2015	208,459		$	48.46
Granted	131,610		$	45.31
Forfeited	(8,463	)	$	46.27
Vested (c)	(98,295	)	$	54.05
Outstanding at December 31, 2016	233,311		$	44.41	$	45.86
Expected to vest	219,844		$	44.35	$	45.98

(a) The 2012 grants vested at 115%.

(b) The 2013 grants vested at 115%.

The estimate of SPUs that are expected to vest is based on highly subjective assumptions that could change over time, including the expected forfeiture rate and achievement of performance targets.

The following table presents the fair value of units vested and the unit-based liabilities paid for unit-based awards related to the strategic performance units:



	Units	Fair Value of Units Vested		Unit-Based Liabilities Paid
		(millions)
Vested or paid in cash in 2014	114,499	$	7	$	8
Vested or paid in cash in 2015	93,551	$	4	$	7
Vested or paid in cash in 2016	98,295	$	7	$	4

Phantom Units - The DERs are paid quarterly in arrears. The following table presents information related to Phantom Units:



	Units		Grant Date Weighted-Average Price Per Unit		Measurement Date Weighted-Average Price Per Unit
Outstanding at January 1, 2014	207,522		$	40.18
Granted	122,650		$	53.73
Forfeited	(11,130	)	$	41.96
Vested	(147,840	)	$	42.10
Outstanding at December 31, 2014	171,202		$	48.11
Granted	147,540		$	47.84
Forfeited	(17,400	)	$	48.40
Vested	(96,974	)	$	44.00
Outstanding at December 31, 2015	204,368		$	49.85
Granted	132,870		$	45.33
Forfeited	(3,240	)	$	48.62
Vested	(126,681	)	$	50.13
Outstanding at December 31, 2016	207,317		$	46.80	$	45.97
Expected to vest	185,785		$	46.72	$	45.90

The following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related to the phantom units:



	Units	Fair Value of Units Vested		Unit-Based Liabilities Paid
		(millions)
Vested or paid in cash in 2014	147,840	$	5	$	5
Vested or paid in cash in 2015	96,974	$	3	$	5
Vested or paid in cash in 2016	126,681	$	4	$	5

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References + Details

Benefits	12 Months Ended
Benefits	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Benefits	Benefits We do not have our own employees. The employees supporting our operations are employees of DCP Midstream, LLC, for which we incur charges under the Services Agreement. All DCP Midstream, LLC employees who have reached the age of 18 and work at least 20 hours per week are eligible for participation in the 401(k) and retirement plan, to which a range of 4% to 7% of each eligible employee’s qualified earnings is contributed to the retirement plan, based on years of service. Effective on January 1, 2015, DCP Midstream, LLC added an automatic enrollment feature in the 401(k) plan, meaning all new employees are enrolled at a 6% contribution level. Employees can opt out of these contribution level or change it at any time. Additionally, DCP Midstream, LLC matches employees’ contributions in the 401(k) plan up to 6% of qualified earnings. During the years ended December 31, 2016, 2015 and 2014, we expensed plan contributions of $29 million, $32 million and $30 million, respectively. DCP Midstream, LLC offers certain eligible executives the opportunity to participate in the EDC Plan. The EDC Plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The EDC Plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the participant’s behalf.

Net Income or Loss per Limited Partner Unit	12 Months Ended
Net Income or Loss per Limited Partner Unit	Dec. 31, 2016
Earnings Per Share [Abstract]
Net Income or Loss per Limited Partner Unit	Net Income or Loss per Limited Partner Unit Our net income or loss is allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after allocating Available Cash generated during the period in accordance with our Partnership agreement. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the Partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period. These required disclosures do not impact our overall net income or loss or other financial results; however, in periods in which aggregate net income exceeds our Available Cash it will have the impact of reducing net income per LPU. Basic and diluted net income or loss per LPU is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per LPU is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method. Dilutive potential units include outstanding awards under the LTIP. The dilutive effect of unit-based awards was 1,105, 7,038 and 10,574 equivalent units during the years ended December 31, 2016, 2015 and 2014 respectively.

Income Taxes Income Taxes

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

We are structured as a master limited partnership with sufficient qualifying income, which is a pass-through entity for federal income tax purposes. We owned a corporation that filed its own federal, foreign and state corporate income tax returns. During the year ended December 31, 2016, we elected to convert the corporation to a limited liability company for federal income tax purposes. The income tax (expense) benefit related to this corporation is included in our income tax (expense) benefit, along with state and local taxes of the limited liability entities.

Income tax (expense) benefit consists of the following:



	Year Ended December 31,
	2016			2015		2014
	(Millions)
Current:
Federal income tax expense	$	(19	)	$	—	$	—
State income tax expense	(2		)	—		(2		)
Deferred:
Federal income tax (expense) benefit	(22		)	97		—
State income tax (expense) benefit	(3		)	5		(9		)
Total income tax (expense) benefit	$	(46	)	$	102	$	(11	)

Deferred income tax assets and liabilities consisted of the following:



	December 31,
	2016			2015
	(Millions)
Deferred income tax assets:
Net operating loss	$	—		$	58
Total deferred income tax assets	—			58
Deferred income tax liabilities:
Property, plant and equipment and intangibles - federal	—			(35		)
Property, plant and equipment and intangibles - state	(28		)	(26		)
Total deferred income tax liabilities	(28		)	(61		)
Net deferred income tax liabilities	(28		)	(3		)

Deferred income tax assets, net - noncurrent	—			23
Deferred income tax liabilities, net - noncurrent	(28		)	(26		)
Net deferred income tax liabilities	$	(28	)	$	(3	)

The state deferred tax liabilities are primarily associated with Texas franchise taxes. During the year ended December 31, 2016, we recorded a reduction to our net federal deferred tax asset of $58 million resulting from the conversion of our corporation to a limited liability company.

As of December 31 2015, our federal net operating losses were $163 million. The net operating losses were fully utilized upon the conversion of our corporation to a limited liability company during the year ended December 31, 2016.

Commitments and Contingent Liabilities

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingent Liabilities

Litigation — We are not a party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our results of operations, financial position, or cash flow.

In January 2016, we reached a settlement with a large producer in the DJ basin and received a cash payment of $89 million, a dedication of a portion of the producer’s production in the DJ Basin under a life of lease agreement and a 15 year dedication of natural gas liquids from the producer and its affiliates to the Sand Hills pipeline in the Delaware basin of the Permian region. The cash consideration was received in February 2016, and we recorded other income, net of $2 million in legal fees, in the consolidated statement of operations for the year December 31, 2016.

Insurance — Our insurance coverage is carried with third-party insurers and with an affiliate of Phillips 66. Our insurance coverage includes: (1) general liability insurance covering third-party exposures; (2) statutory workers’ compensation insurance; (3) automobile liability insurance for all owned, non-owned and hired vehicles; (4) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (5) property insurance, which covers the replacement value of real and personal property and includes business interruption; and (6) insurance covering our directors and officers for acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, fractionating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with laws and regulations at the federal, state and, in some cases, local levels that relate to worker safety, air and water quality, solid and hazardous waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations, worker safety standards, and safety standards applicable to our various facilities. In addition, there is increasing focus (i) from city, state and federal regulatory officials and through litigation, on hydraulic fracturing and the real or perceived environmental impacts of this technique, which indirectly presents some risk to our available supply of natural gas and the resulting supply of NGLs, (ii) from federal regulatory agencies regarding pipeline system safety which could impose additional regulatory burdens and increase the cost of our operations, and (iii) from state and federal regulatory officials regarding the emission of greenhouse gases which could impose regulatory burdens and increase the cost of our operations. Failure to comply with these various health, safety and environmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these existing laws and regulations will not have a material adverse effect on our results of operations, financial position or cash flows.

We make expenditures in connection with environmental matters as part of our normal operations. As of December 31, 2016 and December 31, 2015, environmental liabilities included in our combined balance sheets as other current liabilities were $4 million and $3 million, respectively. As of December 31, 2016 and 2015, environmental liabilities included in our combined balance sheets as other long-term liabilities was $9 million.

Other Commitments and Contingencies — We utilize assets under operating leases in several areas of operation. Consolidated rental expense, including leases with no continuing commitment, totaled $37 million, $34 million, and $31 million for the years ended December 31, 2016, 2015, and 2014, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.

Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2016:



	(Millions)
2017	$	61
2018	37
2019	35
2020	29
2021	21
Thereafter	42
Total minimum rental payments	$	225

Restructuring Costs (Notes)	12 Months Ended
Restructuring Costs (Notes)	Dec. 31, 2016
Restructuring and Related Activities [Abstract]
Restructuring Costs	Restructuring Costs In April 2016, we announced an approximate 10 percent headcount reduction, which involved the elimination of certain operational and corporate positions, as part of their ongoing effort to create efficiencies, reduce costs and transform our business. As a result of this headcount reduction, we recorded one-time employee termination costs of approximately $13 million, which are included in restructuring costs in our consolidated statements of operations for the year ended December 31, 2016. As of December 31, 2016, approximately $1 million of the $13 million restructuring charge incurred is included in other current liabilities. Additionally, we expect to incur further severance costs of less than $1 million related to this phase of our restructuring plan. The severance costs estimate could change based on the number of employees that work through the required service period and the timing of those departures. In January 2015, we announced the initial phase of this cost reduction plan, which involved the elimination of certain corporate employee positions. As a result, we recorded employee termination costs of approximately $11 million, all of which were paid during the year ended December 31, 2015, and are included in restructuring costs in the consolidated statement of operations for the year ended December 31, 2015.

Business Segments

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Business Segments

Concurrent with the completion of the Transaction in the first quarter of 2017, management reevaluated our reportable segments and determined that our operations are organized into two reportable segments: (i) Gathering and Processing and (ii) Logistics and Marketing. Segment information for prior periods has been retrospectively adjusted to furnish comparative information similar to the pooling method to reflect these reportable segments. These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Our Gathering and Processing reportable segment includes operating segments that have been aggregated based on the nature of the products and services provided. Gross margin is a performance measure utilized by management to monitor the operations of each segment.

Our Gathering and Processing segment consists of gathering, compressing, treating, processing natural gas, producing and fractionating NGLs, and recovering and selling condensate. Our Logistics and Marketing segment includes transporting, trading, marketing, and storing natural gas and NGLs, fractionating NGLs, and wholesale propane logistics. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs. Elimination of inter-segment transactions are reflected in the eliminations column.

Year Ended December 31, 2016:



	Gathering and Processing			Logistics and Marketing			Other			Eliminations			Total
	(Millions)
Total operating revenue	$	4,490		$	6,186		$	—		$	(3,783	)	$	6,893
Gross margin (a)	$	1,227		$	205		$	—		$	—		$	1,432
Operating and maintenance expense	(611		)	(43		)	(16		)	—			(670		)
Depreciation and amortization expense	(344		)	(15		)	(19		)	—			(378		)
General and administrative expense	(14		)	(9		)	(269		)	—			(292		)
Other income (expense), net	73			(5		)	(3		)	—			65
Earnings from unconsolidated affiliates	73			209			—			—			282
Interest expense, net	—			—			(321		)	—			(321		)
Gain on sale of assets, net	19			16			—			—			35
Restructuring costs	—			—			(13		)	—			(13		)
Income tax expense	—			—			(46		)	—			(46		)
Net income (loss)	$	423		$	358		$	(687	)	$	—		$	94
Net income attributable to non-controlling interests	(6		)	—			—			—			(6		)
Net income (loss) attributable to partners	$	417		$	358		$	(687	)	$	—		$	88
Non-cash derivative mark-to-market (b)	$	(119	)	$	(20	)	$	—		$	—		$	(139	)
Non-cash lower of cost or market adjustments	$	—		$	3		$	—		$	—		$	3
Capital expenditures	$	107		$	10		$	27		$	—		$	144
Investments in unconsolidated affiliates, net	$	1		$	52		$	—		$	—		$	53

Year Ended December 31, 2015:



	Gathering and Processing			Logistics and Marketing			Other			Eliminations			Total
	(Millions)
Total operating revenue	$	4,910		$	6,487		$	—		$	(3,967	)	$	7,430
Gross margin (a)	$	1,213		$	236		$	—		$	—		$	1,449
Operating and maintenance expense	(668		)	(49		)	(15		)	—			(732		)
Depreciation and amortization expense	(343		)	(16		)	(18		)	—			(377		)
General and administrative expense	(22		)	(11		)	(248		)	—			(281		)
Other expense, net	(1		)	(8		)	(1		)	—			(10		)
Asset impairment	(876		)	(9		)	(27		)	—			(912		)
Earnings from unconsolidated affiliates	54			130			—			—			184
Interest expense, net	—			—			(320		)	—			(320		)
Gain on sale of assets, net	42			—			—			—			42
Restructuring costs	—			—			(11		)	—			(11		)
Income tax benefit	—			—			102			—			102
Net income (loss)	$	(601	)	$	273		$	(538	)	$	—		$	(866	)
Net income attributable to non-controlling interests	(5		)	—			—			—			(5		)
Net income (loss) attributable to partners	$	(606	)	$	273		$	(538	)	$	—		$	(871	)
Non-cash derivative mark-to-market (b)	$	47		$	(1	)	$	—		$	—		$	46
Non-cash lower of cost or market adjustments	$	—		$	8		$	—		$	—		$	8
Capital expenditures	$	729		$	52		$	30		$	—		$	811
Investments in unconsolidated affiliates, net	$	15		$	49		$	—		$	—		$	64

Year Ended December 31, 2014:



	Gathering and Processing			Logistics and Marketing			Other			Eliminations			Total
	(Millions)
Total operating revenue	$	9,873		$	12,649		$	—		$	(8,497	)	$	14,025
Gross margin (a)	$	1,971		$	226		$	—		$	—		$	2,197
Operating and maintenance expense	(725		)	(44		)	(4		)	—			(773		)
Depreciation and amortization expense	(315		)	(17		)	(16		)	—			(348		)
General and administrative expense	(27		)	(14		)	(236		)	—			(277		)
Other expense, net	(5		)	—			(2		)	—			(7		)
Asset impairment	(18		)	—			—			—			(18		)
Earnings from unconsolidated affiliates	5			77			—			—			82
Interest expense, net	—			—			(287		)	—			(287		)
Loss on sale of assets, net	(7		)	—			—			—			(7		)
Income tax expense	—			—			(11		)	—			(11		)
Net income (loss)	$	879		$	228		$	(556	)	$	—		$	551
Net income attributable to non-controlling interests	(4		)	—			—			—			(4		)
Net income (loss) attributable to partners	$	875		$	228		$	(556	)	$	—		$	547
Non-cash derivative mark-to-market (b)	$	39		$	4		$	—		$	—		$	43
Non-cash lower of cost or market adjustments	$	—		$	24		$	—		$	—		$	24
Capital expenditures	$	1,272		$	62		$	50		$	—		$	1,384
Investments in unconsolidated affiliates, net	$	75		$	86		$	—		$	—		$	161



	December 31,
	2016		2015
	(Millions)
Segment long-term assets:
Gathering and Processing	$	9,053	$	9,431
Logistics and Marketing	3,278		3,339
Other (c)	286		311
Total long-term assets	12,617		13,081
Current assets	994		804
Total assets	$	13,611	$	13,885

(a)

Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs. Gross margin is viewed as a non-GAAP financial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.


(b)	Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts.


(c)	Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 33
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8971-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8595-108599

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8380-108599

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 35
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8984-108599

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e9031-108599

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e9054-108599

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8538-108599

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
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-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8864-108599

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8906-108599

+ Details

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information



	Year Ended December 31,
	2016			2015			2014
	(Millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	306		$	293		$	274
Cash paid for income taxes, net of income tax refunds	$	2		$	3		$	4
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable	$	27		$	35		$	145
Other non-cash changes in property, plant and equipment	$	(3	)	$	(19	)	$	27
Contribution of assets from our predecessor	$	—		$	1,500		$	—

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

Our consolidated results of operations by quarter for the years ended December 31, 2016 and 2015 were as follows (millions, except per unit amounts):



2016	First			Second			Third			Fourth			Year Ended December 31, 2016
Total operating revenues	$	1,464		$	1,623		$	1,823		$	1,983		$	6,893
Operating income (loss)	$	80		$	(12	)	$	92		$	19		$	179
Net income (loss)	$	65		$	(21	)	$	89		$	(39	)	$	94
Net income attributable to non-controlling interests	$	—		$	(1	)	$	—		$	(5	)	$	(6	)
Net income attributable to partners	$	65		$	(22	)	$	89		$	(44	)	$	88
Net loss attributable to predecessor operations	$	(7	)	$	(67	)	$	(31	)	$	(119	)	$	(224	)
Net income allocable to limited partners	$	41		$	14		$	89		$	44		$	188
Basic and diluted net income per limited partner unit	$	0.36		$	0.12		$	0.78		$	0.38		$	1.64



2015	First			Second			Third			Fourth			Year Ended December 31, 2015
Total operating revenues	$	2,020		$	1,849		$	1,870		$	1,691		$	7,430
Operating income (loss)	$	40		$	(463	)	$	57		$	(466	)	$	(832	)
Net (loss) income	$	(17	)	$	(491	)	$	24		$	(382	)	$	(866	)
Net income attributable to non-controlling interests	$	—		$	—		$	(1	)	$	(4	)	$	(5	)
Net income attributable to partners	$	(17	)	$	(491	)	$	23		$	(386	)	$	(871	)
Net loss attributable to predecessor operations	$	(86	)	$	(489	)	$	(48	)	$	(476	)	$	(1,099	)
Net income (loss) allocable to limited partners	$	38		$	(33	)	$	40		$	59		$	104
Basic and diluted net income (loss) per limited partner unit	$	0.33		$	(0.29	)	$	0.35		$	0.51		$	0.91

Supplementary Information - Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2016

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Supplementary Information - Condensed Consolidating Financial Information

Supplementary Information — Condensed Consolidating Financial Information

The following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a 100% owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to present DCP Midstream, LP’s results on a consolidated basis. The parent guarantor has agreed to fully and unconditionally guarantee debt securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.



	Condensed Consolidating Balance Sheet
	December 31, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	1		$	—		$	1
Accounts receivable, net	—		—			792			—			792
Inventories	—		—			72			—			72
Other	—		—			129			—			129
Total current assets	—		—			994			—			994
Property, plant and equipment, net	—		—			9,069			—			9,069
Goodwill and intangible assets, net	—		—			373			—			373
Advances receivable — consolidated subsidiaries	2,953		2,760			—			(5,713		)	—
Investments in consolidated subsidiaries	3,868		6,587			—			(10,455		)	—
Investments in unconsolidated affiliates	—		—			2,969			—			2,969
Other long-term assets	—		—			206			—			206
Total assets	$	6,821	$	9,347		$	13,611		$	(16,168	)	$	13,611
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	72		$	1,051		$	—		$	1,123
Current maturities of long-term debt	—		500			—			—			500
Advances payable — consolidated subsidiaries	—		—			5,713			(5,713		)	—
Long-term debt	—		4,907			—			—			4,907
Other long-term liabilities	—		—			228			—			228
Total liabilities	—		5,479			6,992			(5,713		)	6,758
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	6,821		3,871			6,592			(10,455		)	6,829
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	6,821		3,868			6,587			(10,455		)	6,821
Non-controlling interests	—		—			32			—			32
Total equity	6,821		3,868			6,619			(10,455		)	6,853
Total liabilities and equity	$	6,821	$	9,347		$	13,611		$	(16,168	)	$	13,611



	Condensed Consolidating Balance Sheet
	December 31, 2015
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	3		$	—		$	3
Accounts receivable, net	—		—			544			—			544
Inventories	—		—			51			—			51
Other	—		—			206			—			206
Total current assets	—		—			804			—			804
Property, plant and equipment, net	—		—			9,428			—			9,428
Goodwill and intangible assets, net	—		—			391			—			391
Advances receivable — consolidated subsidiaries	3,436		3,353			—			(6,789		)	—
Investments in consolidated subsidiaries	3,623		6,011			—			(9,634		)	—
Investments in unconsolidated affiliates	—		—			2,992			—			2,992
Other long-term assets	—		—			270			—			270
Total assets	$	7,059	$	9,364		$	13,885		$	(16,423	)	$	13,885
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	72		$	827		$	—		$	899
Advances payable — consolidated subsidiaries			—			6,789			(6,789		)	—
Long-term debt	—		5,669			—			—			5,669
Other long-term liabilities	—		—			225			—			225
Total liabilities	—		5,741			7,841			(6,789		)	6,793
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	7,059		3,626			6,016			(9,634		)	7,067
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	7,059		3,623			6,011			(9,634		)	7,059
Non-controlling interests	—		—			33			—			33
Total equity	7,059		3,623			6,044			(9,634		)	7,092
Total liabilities and equity	$	7,059	$	9,364		$	13,885		$	(16,423	)	$	13,885



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2016
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	—	$	—		$	6,269		$	—		$	6,269
Transportation, processing and other	—		—			647			—			647
Trading and marketing losses, net	—		—			(23		)	—			(23		)
Total operating revenues	—		—			6,893			—			6,893
Operating costs and expenses:
Purchases of natural gas and NGLs	—		—			5,461			—			5,461
Operating and maintenance expense	—		—			670			—			670
Depreciation and amortization expense	—		—			378			—			378
General and administrative expense	—		—			292			—			292
Other income, net	—		—			(65		)	—			(65		)
Restructuring costs	—		—			13						13
Gain on sale of assets, net	—		—			(35		)	—			(35		)
Total operating costs and expenses	—		—			6,714			—			6,714
Operating income	—		—			179			—			179
Interest expense, net	—		(321		)	—			—			(321		)
Income from consolidated subsidiaries	88		409			—			(497		)	—
Earnings from unconsolidated affiliates	—		—			282			—			282
Income before income taxes	88		88			461			(497		)	140
Income tax expense	—		—			(46		)	—			(46		)
Net income	88		88			415			(497		)	94
Net income attributable to non-controlling interests	—		—			(6		)	—			(6		)
Net income attributable to partners	$	88	$	88		$	409		$	(497	)	$	88



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2016
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	88	$	88	$	415		$	(497	)	$	94
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		—		—			—			—
Other comprehensive income from consolidated subsidiaries	—		—		—			—			—
Total other comprehensive income	—		—		—			—			—
Total comprehensive income	88		88		415			(497		)	94
Total comprehensive income attributable to non-controlling interests	—		—		(6		)	—			(6		)
Total comprehensive income attributable to partners	$	88	$	88	$	409		$	(497	)	$	88



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	—		$	—		$	6,779		$	—	$	6,779
Transportation, processing and other	—			—			532			—		532
Trading and marketing gains, net	—			—			119			—		119
Total operating revenues	—			—			7,430			—		7,430
Operating costs and expenses:
Purchases of natural gas and NGLs	—			—			5,981			—		5,981
Operating and maintenance expense	—			—			732			—		732
Depreciation and amortization expense	—			—			377			—		377
General and administrative expense	—			—			281			—		281
Asset impairments	—			—			912			—		912
Other expense, net	—			—			10			—		10
Restructuring costs	—			—			11			—		11
Gain on sale of assets, net	—			—			(42		)	—		(42		)
Total operating costs and expenses	—			—			8,262			—		8,262
Operating loss	—			—			(832		)	—		(832		)
Interest expense, net	—			(320		)	—			—		(320		)
Loss from consolidated subsidiaries	(871		)	(551		)	—			1,422		—
Earnings from unconsolidated affiliates	—			—			184			—		184
Loss before income taxes	(871		)	(871		)	(648		)	1,422		(968		)
Income tax benefit	—			—			102			—		102
Net loss	(871		)	(871		)	(546		)	1,422		(866		)
Net income attributable to non-controlling interests	—			—			(5		)	—		(5		)
Net loss attributable to partners	$	(871	)	$	(871	)	$	(551	)	$	1,422	$	(871	)



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net loss	$	(871	)	$	(871	)	$	(546	)	$	1,422		$	(866	)
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—			1			—			—			1
Other comprehensive income from consolidated subsidiaries	1			—			—			(1		)	—
Total other comprehensive income	1			1			—			(1		)	1
Total comprehensive loss	(870		)	(870		)	(546		)	1,421			(865		)
Total comprehensive loss attributable to non-controlling interests	—			—			(5		)	—			(5		)
Total comprehensive loss attributable to partners	$	(870	)	$	(870	)	$	(551	)	$	1,421		$	(870	)



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2014
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	—	$	—		$	13,420		$	—		$	13,420
Transportation, processing and other	—		—			517			—			517
Trading and marketing gains, net	—		—			88			—			88
Total operating revenues	—		—			14,025			—			14,025
Operating costs and expenses:
Purchases of natural gas and NGLs	—		—			11,828			—			11,828
Operating and maintenance expense	—		—			773			—			773
Depreciation and amortization expense	—		—			348			—			348
General and administrative expense	—		—			277			—			277
Asset impairments	—		—			18			—			18
Other expense, net	—		—			7			—			7
Loss on sale of assets, net	—		—			7			—			7
Total operating costs and expenses	—		—			13,258			—			13,258
Operating income	—		—			767			—			767
Interest expense, net	—		(287		)	—			—			(287		)
Earnings from unconsolidated affiliates	—		—			82			—			82
Income from consolidated subsidiaries	547		834			—			(1,381		)	—
Income before income taxes	547		547			849			(1,381		)	562
Income tax expense	—		—			(11		)	—			(11		)
Net income	547		547			838			(1,381		)	551
Net income attributable to non-controlling interests	—		—			(4		)	—			(4		)
Net income attributable to partners	$	547	$	547		$	834		$	(1,381	)	$	547



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2014
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	547	$	547	$	838		$	(1,381	)	$	551
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		2		—			—			2
Other comprehensive income from consolidated subsidiaries	2		—		—			(2		)	—
Total other comprehensive income	2		2		—			(2		)	2
Total comprehensive income	549		549		838			(1,383		)	553
Total comprehensive income attributable to non-controlling interests	—		—		(4		)	—			(4		)
Total comprehensive income attributable to partners	$	549	$	549	$	834		$	(1,383	)	$	549



	Condensed Consolidating Statement of Cash Flows
	Year Ended December 31, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(305	)	$	950		$	—		$	645
INVESTING ACTIVITIES:
Intercompany transfers	483			585			—			(1,068		)	—
Capital expenditures	—			—			(144		)	—			(144		)
Investments in unconsolidated affiliates, net	—			—			(53		)	—			(53		)
Proceeds from sale of assets	—			—			163			—			163
Net cash provided by (used in) investing activities	483			585			(34		)	(1,068		)	(34		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(1,068		)	1,068			—
Proceeds from long-term debt	—			3,353			—			—			3,353
Payments of long-term debt	—			(3,628		)	—			—			(3,628		)
Payments of deferred financing costs	—			(5		)	—			—			(5		)
Net change in advances to predecessor from DCP Midstream, LLC	—			—			157			—			157
Distributions to limited partners and general partner	(483		)	—			—			—			(483		)
Distributions to non-controlling interests	—			—			(7		)	—			(7		)
Net cash used in financing activities	(483		)	(280		)	(918		)	1,068			(613		)
Net change in cash and cash equivalents	—			—			(2		)	—			(2		)
Cash and cash equivalents, beginning of period	—			—			3			—			3
Cash and cash equivalents, end of period	$	—		$	—		$	1		$	—		$	1



	Condensed Consolidating Statements of Cash Flows
	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(311	)	$	753		$	—		$	442
INVESTING ACTIVITIES:
Intercompany transfers	(1,049		)	1,283			—			(234		)	—
Capital expenditures	—			—			(811		)	—			(811		)
Investments in unconsolidated affiliates, net	—			—			(64		)	—			(64		)
Proceeds from sale of assets	—			—			164			—			164
Net cash (used in) provided by investing activities	(1,049		)	1,283			(711		)	(234		)	(711		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(234		)	234			—
Proceeds from long-term debt	—			7,216			—			—			7,216
Payments of long-term debt	—			(7,196		)	—			—			(7,196		)
Payments of commercial paper, net	—			(1,012		)	—			—			(1,012		)
Payment of deferred financing costs	—			(4		)	—			—			(4		)
Proceeds from issuance of common units, net of offering costs	31			—			—			—			31
Net change in advances to predecessor from DCP Midstream, LLC	1,500			—			197			—			1,697
Distributions to limited partners and general partner	(482		)	—			—			—			(482		)
Distributions to non-controlling interests	—						(5		)	—			(5		)
Net cash provided by (used in) financing activities	1,049			(996		)	(42		)	234			245
Net change in cash and cash equivalents	—			(24		)	—			—			(24		)
Cash and cash equivalents, beginning of period	—			24			3			—			27
Cash and cash equivalents, end of period	$	—		$	—		$	3		$	—		$	3



	Condensed Consolidating Statements of Cash Flows
	Year Ended December 31, 2014
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(271	)	$	1,088		$	—		$	817
INVESTING ACTIVITIES:
Intercompany transfers	(581		)	(141		)	—			722			—
Capital expenditures	—			—			(1,384		)	—			(1,384		)
Investments in unconsolidated affiliates, net	—			—			(161		)	—			(161		)
Proceeds from sale of assets	—			—			30			—			30
Net cash used in investing activities	(581		)	(141		)	(1,515		)	722			(1,515		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			722			(722		)	—
Proceeds from long-term debt	—			719			—			—			719
Payments of issuance of commercial paper, net	—			(288		)	—			—			(288		)
Payment of deferred financing costs	—			(12		)	—			—			(12		)
Proceeds from issuance of common units, net of offering costs	1,001			—			—			—			1,001
Distributions to limited partners and general partner	(420		)	—			—			—			(420		)
Distributions to non-controlling interests	—			—			(5		)	—			(5		)
Net change in advances to predecessor from DCP Midstream, LLC	—			—			(301		)	—			(301		)
Net cash provided by financing activities	581			419			416			(722		)	694
Net change in cash and cash equivalents	—			7			(11		)	—			(4		)
Cash and cash equivalents, beginning of year	—			17			14			—			31
Cash and cash equivalents, end of year	$	—		$	24		$	3		$	—		$	27

- Definition

The entire disclosure for condensed financial information, including the financial position, cash flows, and the results of operations of the registrant (parent company) as of the same dates or for the same periods for which audited consolidated financial statements are being presented. Alternatively, the details of this disclosure can be reported by the specific parent company taxonomy elements, indicating the appropriate date and period contexts in an instance document.

+ References + Details

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On December 30, 2016, we entered into a Contribution Agreement with DCP Midstream, LLC and DCP Midstream Operating, LP. The Transaction closed effective January 1, 2017. For additional information regarding the Transaction, see Note 4 - Acquisitions. Effective January 11, 2017, we changed our name to "DCP Midstream, LP" from "DCP Midstream Partners, LP" (the Name Change"). In connection with the Name Change, the ticker symbol for our common units representing limited partner interests listed on the NYSE changed from “DPM” to “DCP” effective at the open of the NYSE on January 23, 2017. On January 26, 2017, we announced that the board of directors of the General Partner declared a quarterly distribution of $0.78 per unit. The distribution was paid on February 14, 2017 to unitholders of record on February 7, 2017, except that the owners of the Partnership's General Partner will receive distributions on the units issued on January 1, 2017 beginning with the first quarter 2017 declared distribution. In February 2017, we further amended our $1.25 billion senior unsecured revolving credit agreement that matures on May 1, 2019, to increase the aggregate commitments under the unsecured revolving credit facility to approximately $1.4 billion. The Amended and Restated Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions. On April 25, 2017, we announced that the board of directors of the General Partner declared a quarterly distribution of $0.78 per unit. The distribution was paid on May 15, 2017 to unitholders of record on May 9, 2017.

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Consolidation

The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercise control.

Equity Method Investments

Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method.

Use of Estimates

Cash and Cash Equivalents

Allowance for Doubtful Accounts

Inventories

Inventories - Inventories, which consist primarily of NGLs and natural gas, are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory.

Property, Plant and Equipment

Asset Retirement Obligations

Goodwill and Intangible Assets

Investments in Unconsolidated Affiliates

Long-Lived Assets


•	significant adverse change in legal factors or business climate;


•	a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;


•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;


•	significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;


•	a significant adverse change in the market value of an asset; or


•	a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

Unamortized Debt Discount and Expense

Revenue Recognition

We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the following arrangements:

•

Our trading and marketing of natural gas and NGLs consists of physical purchases and sales, as well as positions in derivative instruments.

We recognize revenues for sales and services under the four revenue recognition criteria, as follows:


•	Persuasive evidence of an arrangement exists - Our customary practice is to enter into a written contract.


•	Delivery - Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.


•	The fee is fixed or determinable - We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

•

Significant Customers

Environmental Expenditures

Income Taxes

Net Income or Loss per Limited Partner Unit

New Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. This ASU is effective for interim and annual reporting periods beginning after December 15, 2017, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated statement of cash flows.

FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases. This ASU is effective for interim and annual reporting periods beginning after December 15, 2018, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.

FASB ASU, 2015-16 “Business Combinations (Topic 805),” or ASU 2015-16 - In September 2015, the FASB issued ASU 2015-16, which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU is effective for interim and annual reporting periods beginning after December 15, 2016. The Partnership has adpoted the ASU and it did not have any impact on our consolidated results of operations, cash flows and financial position.

FASB ASU 2015-02 “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” or ASU 2015-02 - In February 2015, the FASB issued ASU 2015-02, which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. This ASU was effective for annual reporting periods beginning after December 15, 2015. The retrospective adoption of this ASU has been implemented and did not have any impact on our consolidated results of operations, cash flows and financial position.

FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations and amendments - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. We plan to adopt this ASU using the modified retrospective method. The initial cumulative effect will be recognized at the date of adoption. Our evaluation of ASU 2014-09 is ongoing and not complete. The FASB has issued and may issue in the future, interpretative guidance, which may cause our evaluation to change. Accordingly, at this time we cannot estimate the impact upon adoption.

Fair Value Measurement

Determination of Fair Value

•

Valuation Hierarchy


•	Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.


•	Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.


•	Level 3 — inputs are unobservable and considered significant to the fair value measurement.

Commodity Derivative Assets and Liabilities

Interest Rate Derivative Assets and Liabilities

Benefits

Nonfinancial Assets and Liabilities

Derivatives

Commodity Price Risk

Natural Gas Asset Based Trading and Marketing

Commodity Cash Flow Hedges

Commodity Cash Flow Protection Activities

NGL Proprietary Trading

We employ established risk limits, policies and procedures to manage risks associated with our natural gas asset based trading and marketing and NGL proprietary trading.

Interest Rate Risk

Credit Risk

Contingent Credit Features


•	If we were to have an effective event of default under our Amended and Restated Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.


•	Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liability position, when our credit rating is below investment grade.

•

Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features.

Collateral

Offsetting

Agreements and Transactions with Affiliates (Tables)

12 Months Ended

Dec. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Summary of Transactions with Affiliates

The following table summarizes our transactions with affiliates:



	Year Ended December 31,
	2016		2015		2014
	(Millions)
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	909	$	695	$	1,960
Purchases of natural gas and NGLs from affiliates	$	18	$	—	$	11
Operating and maintenance and general administrative expenses	$	2	$	4	$	3
Enbridge (including Spectra Energy Corp.):
Transportation, storage and processing to affiliates	$	—	$	—	$	14
Purchases of natural gas and NGLs from affiliates	$	33	$	50	$	88
Operating and maintenance and general administrative expenses	$	4	$	6	$	10
Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates	$	43	$	70	$	70
Transportation, storage and processing	$	5	$	3	$	12
Purchases of natural gas and NGLs from affiliates	$	432	$	368	$	366

We had balances with affiliates as follows:



	December 31,
	2016		2015
	(Millions)
Phillips 66 (including its affiliates):
Accounts receivable	$	115	$	54
Accounts payable	$	4	$	3
Other assets	$	2	$	1
Enbridge (including Spectra Energy Corp.):
Accounts receivable	$	1	$	—
Accounts payable	$	3	$	4
Other assets	$	1	$	1
Other liabilities	$	1	$	—
Unconsolidated affiliates:
Accounts receivable	$	18	$	21
Accounts payable	$	41	$	33
Other assets	$	5	$	31

The following table summarizes our investments in unconsolidated affiliates:



		Carrying Value as of
	Percentage Ownership	December 31, 2016		December 31, 2015
		(Millions)
DCP Sand Hills Pipeline, LLC	66.67%	$	1,507	$	1,492
DCP Southern Hills Pipeline, LLC	66.67%	754		764
Discovery Producer Services LLC	40.00%	385		405
Front Range Pipeline LLC	33.33%	165		170
Texas Express Pipeline LLC	10.00%	93		96
Panola Pipeline Company, LLC	15.00%	25		19
Mont Belvieu Enterprise Fractionator	12.50%	23		25
Mont Belvieu 1 Fractionator	20.00%	10		11
Other	Various	7		10
Total investments in unconsolidated affiliates		$	2,969	$	2,992

Inventories (Tables)

12 Months Ended

Dec. 31, 2016

Inventory Disclosure [Abstract]

Schedule of Inventories

Inventories were as follows:



	December 31,
	2016		2015
	(Millions)
Natural gas	$	28	$	29
NGLs	44		22
Total inventories	$	72	$	51

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Classification of Property, Plant and Equipment

Property, plant and equipment by classification were as follows:



		December 31,
	Depreciable Life	2016			2015
		(Millions)
Gathering and transmission systems	20 — 50 Years	$	8,560		$	8,815
Processing, storage, and terminal facilities	35 — 60 Years	5,134			5,102
Other	3 — 30 Years	502			485
Construction work in progress		171			196
Property, plant and equipment		14,367			14,598
Accumulated depreciation		(5,298		)	(5,170		)
Property, plant and equipment, net		$	9,069		$	9,428

Schedule of Changes in Asset Retirement Obligations

The following table summarizes changes in the asset retirement obligations included in our balance sheets:



	December 31,
	2016 (a)			2015 (a)
	(millions)
Balance, beginning of period	$	120		$	117
Accretion expense	7			7
Revisions in estimated cash flows	(3		)	(4		)
Balance, end of period	$	124		$	120

Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

The change in carrying amount of goodwill in each of our reportable segments was as follows:



	Year Ended December 31,
	2016								2015
	(Millions)
	Gathering and Processing			Logistics and Marketing		Total			Gathering and Processing			Logistics and Marketing		Total
Balance, beginning of period	$	170		$	72	$	242		$	632		$	72	$	704
Impairment	—			—		—			(460		)	—		(460		)
Dispositions	$	(6	)	$	—	$	(6	)	$	(2	)	$	—	$	(2	)
Balance, end of period	$	164		$	72	$	236		$	170		$	72	$	242

Schedule of Finite-Lived Intangible Assets

The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows:



	December 31,
	2016			2015
	(Millions)
Gross carrying amount	$	410		$	410
Accumulated amortization	(151		)	(139		)
Accumulated impairment	(122		)	(122		)
Intangible assets, net	$	137		$	149

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense

Estimated future amortization for these intangible assets is as follows:



Estimated Future Amortization
(Millions)
2017	$	11
2018	11
2019	11
2020	11
2021	11
Thereafter	82
Total	$	137

Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Affiliates

The following table summarizes our transactions with affiliates:



	Year Ended December 31,
	2016		2015		2014
	(Millions)
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates	$	909	$	695	$	1,960
Purchases of natural gas and NGLs from affiliates	$	18	$	—	$	11
Operating and maintenance and general administrative expenses	$	2	$	4	$	3
Enbridge (including Spectra Energy Corp.):
Transportation, storage and processing to affiliates	$	—	$	—	$	14
Purchases of natural gas and NGLs from affiliates	$	33	$	50	$	88
Operating and maintenance and general administrative expenses	$	4	$	6	$	10
Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates	$	43	$	70	$	70
Transportation, storage and processing	$	5	$	3	$	12
Purchases of natural gas and NGLs from affiliates	$	432	$	368	$	366

We had balances with affiliates as follows:



	December 31,
	2016		2015
	(Millions)
Phillips 66 (including its affiliates):
Accounts receivable	$	115	$	54
Accounts payable	$	4	$	3
Other assets	$	2	$	1
Enbridge (including Spectra Energy Corp.):
Accounts receivable	$	1	$	—
Accounts payable	$	3	$	4
Other assets	$	1	$	1
Other liabilities	$	1	$	—
Unconsolidated affiliates:
Accounts receivable	$	18	$	21
Accounts payable	$	41	$	33
Other assets	$	5	$	31

The following table summarizes our investments in unconsolidated affiliates:



		Carrying Value as of
	Percentage Ownership	December 31, 2016		December 31, 2015
		(Millions)
DCP Sand Hills Pipeline, LLC	66.67%	$	1,507	$	1,492
DCP Southern Hills Pipeline, LLC	66.67%	754		764
Discovery Producer Services LLC	40.00%	385		405
Front Range Pipeline LLC	33.33%	165		170
Texas Express Pipeline LLC	10.00%	93		96
Panola Pipeline Company, LLC	15.00%	25		19
Mont Belvieu Enterprise Fractionator	12.50%	23		25
Mont Belvieu 1 Fractionator	20.00%	10		11
Other	Various	7		10
Total investments in unconsolidated affiliates		$	2,969	$	2,992

Earnings from Investments in Unconsolidated Affiliates

Earnings from investments in unconsolidated affiliates were as follows:



		Year Ended December 31,
		2016		2015		2014
	(Millions)
DCP Sand Hills Pipeline, LLC		$	110	$	63	$	26
Discovery Producer Services LLC		73		54		7
DCP Southern Hills Pipeline, LLC		44		18		15
Front Range Pipeline LLC		19		17		2
Mont Belvieu Enterprise Fractionator		16		15		17
Mont Belvieu 1 Fractionator		9		9		12
Texas Express Pipeline LLC		9		8		3
Other		2		—		—
Total earnings from unconsolidated affiliates		$	282	$	184	$	82

Equity Method Investment Summarized Financial Information, Statement of Operations

The following tables summarize the combined financial information of our investments in unconsolidated affiliates:



		Year Ended December 31,
		2016		2015		2014
	(Millions)
Statements of operations (a):
Operating revenue		$	1,311	$	1,142	$	859
Operating expenses		$	539	$	541	$	503
Net income		$	768	$	600	$	354

Equity Method Investment Summarized Financial Information, Balance Sheet



	December 31,
	2016			2015
	(Millions)
Balance sheets (a):
Current assets	$	232		$	240
Long-term assets	5,274			5,224
Current liabilities	(156		)	(167		)
Long-term liabilities	(205		)	(230		)
Net assets	$	5,145		$	5,067

(a) In accordance with the Panola Pipeline Company, LLC, or Panola, joint venture agreement, earnings

began to accrue to the Partnership’s interest on February 1, 2016. Accordingly, activity related to Panola

is included in the above tables as of and for the year ended December 31, 2016.

Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Schedule of Asset Measured At Fair Value On Nonrecurring Basis

The following table presents the carrying value of assets measured at fair value on a non-recurring basis, by consolidated balance sheet caption and by valuation hierarchy, as of December 31, 2015:



	Fair Value Measurements Using
	Net Carrying Value		Level 1		Level 2		Level 3		Asset Impairments
	(millions)
December 31, 2015:
Goodwill	$	—	$	—	$	—	$	—	$	460
Property, plant and equipment	87		—		—		87		302
Intangible assets	36		—		—		36		122
Other assets	50		—		—		50		28
Total non-recurring assets measured at fair value	$	173	$	—	$	—	$	173	$	912

Financial Instruments Carried at Fair Value

The following table presents the financial instruments carried at fair value as of December 31, 2016 and 2015, by consolidated balance sheet caption and by valuation hierarchy, as described above:



	December 31, 2016												December 31, 2015
	Level 1			Level 2			Level 3			Total Carrying Value			Level 1			Level 2			Level 3			Total Carrying Value
	(Millions)
Current assets:
Commodity derivatives (a)	$	5		$	28		$	9		$	42		$	23		$	98		$	35		$	156
Short-term investments (b)	$	—		$	—		$	—		$	—		$	2		$	—		$	—		$	2
Long-term assets:
Commodity derivatives (c)	$	—		$	—		$	5		$	5		$	3		$	12		$	4		$	19
Mutual funds (d)	$	—		$	—		$	—		$	—		$	8		$	—		$	—		$	8
Current liabilities:
Commodity derivatives (e)	$	(11	)	$	(57	)	$	(23	)	$	(91	)	$	(16	)	$	(30	)	$	(23	)	$	(69	)
Long-term liabilities:
Commodity derivatives (f)	$	(1	)	$	—		$	—		$	(1	)	$	(1	)	$	(5	)	$	(6	)	$	(12	)


(a)	Included in current unrealized gains on derivative instruments in our consolidated balance sheets.


(b)	Includes short-term money market securities included in cash and cash equivalents in our consolidated balance sheets.


(c)	Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.


(d)	Included in other long-term assets in our consolidated balance sheets.


(e)	Included in current unrealized losses on derivative instruments in our consolidated balance sheets.


(f)	Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets.

Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation



	Commodity Derivative Instruments
	Current Assets			Long- Term Assets		Current Liabilities			Long- Term Liabilities
	(Millions)
Year ended December 31, 2016 (a):
Beginning balance	$	35		$	4	$	(23	)	$	(6	)
Net unrealized gains (losses) included in earnings (b)	3			1		(15		)	6
Settlements	(29		)	—		15			—
Ending balance	$	9		$	5	$	(23	)	$	—
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	9		$	3	$	(23	)	$	6
Year ended December 31, 2015 (a):
Beginning balance	$	23		$	3	$	(45	)	$	(12	)
Net unrealized gains (losses) included in earnings (b)	(82		)	1		(29		)	6
Transfers out of Level 3 (c)	—			—		1			—
Settlements	(25		)	—		50			—
Novation (d)	119			—		—			—
Ending balance	$	35		$	4	$	(23	)	$	(6	)
Net unrealized gains (losses) on derivatives still held included in earnings (b)	$	(84	)	$	1	$	(23	)	$	4


(a)	There were no purchases, issuances or sales of derivatives or transfers into/out of Level 3 for the years ended December 31, 2016 and 2015.


(b)	Represents the amount of total gains or losses for the period, included in trading and marketing gains or losses, net, in our consolidated statements of operations.


(c)	Amounts transferred out of Level 3 are reflected at fair value as of the end of the period.


(d)	Represents the March 2015 novation of certain fixed price commodity derivatives.

Schedule of Valuation Processes



	December 31, 2016
Product Group	Fair Value			Forward Curve Range
	(Millions)
Assets
NGLs	$	14		$0.25-$1.20	Per gallon
Liabilities
NGLs	$	(23	)	$0.25-$1.23	Per gallon

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]

As of December 31, 2016 and 2015, the carrying value and fair value of our total debt, includiing current maturities, were as follows:

December 31, 2016

December 31, 2015

Carrying Value (a)

Fair Value

Carrying Value (a)

Fair Value

(Millions)

Total debt

5,430

5,395

5,704

4,754

Debt (Tables)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Schedule of Debt



	December 31,
	2016			2015
	(Millions)
Senior notes:
Issued November, 2012, interest at 2.500% payable semi-annually, due December, 2017	500			500
Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a)	450			450
Issued March, 2014, interest at 2.700% payable semi-annually, due April, 2019	325			325
Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a)	600			600
Issued September 2011, interest at 4.750% payable semiannually, due September 2021	500			500
Issued March, 2012, interest at 4.950% payable semi-annually, due April, 2022	350			350
Issued March, 2013, interest at 3.875% payable semi-annually, due March, 2023	500			500
Issued August 2000, interest at 8.125% payable semiannually, due August 2030 (a)	300			300
Issued October 2006, interest at 6.450% payable semiannually, due November 2036	300			300
Issued September 2007, interest at 6.750% payable semiannually, due September 2037	450			450
Issued March, 2014, interest at 5.600% payable semi-annually, due April, 2044	400			400
Junior subordinated notes:
Issued May 2013, interest at 5.850% payable semiannually, due May 2043	550			550
Credit facilities with financial institutions:
Revolving credit agreement terminated December, 2016, weighted average interest rate of 2.930% at December 31, 2015	—			96
Revolving credit agreement, weighted-average variable interest rate of 2.014% and 1.572%, as of December 31, 2016 and December 31, 2015, respectively, due May 2019	195			375
Fair value adjustments related to interest rate swap fair value hedges (a)	24			26
Unamortized issuance costs	(23		)	(35		)
Unamortized discount	(14		)	(18		)
Total debt	5,407			5,669
Current maturities of long-term debt	500			—
Total long-term debt	$	4,907		$	5,669

Future Maturities of Long-Term Debt

The future maturities of debt in the year indicated are as follows:



	Debt Maturities
	(Millions)
2017	$	500
2018	—
2019	970
2020	600
2021	500
Thereafter	2,850
	5,420
Fair value adjustments related to interest rate swap fair value hedges	24
Unamortized issuance costs	(23		)
Unamortized discount	(14		)
Total	$	5,407

Risk Management and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of Gross and Net Amounts of Derivative Instruments

The following summarizes the gross and net amounts of our derivative instruments:



	December 31, 2016								December 31, 2015
	Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)		Net Amount			Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet			Amounts Not Offset in the Balance Sheet - Financial Instruments (a)			Net Amount
	(Millions)
Assets:
Commodity derivatives	$	47		$	—	$	47		$	175		$	(1	)	$	174
Liabilities:
Commodity derivatives	$	(92	)	$	—	$	(92	)	$	(81	)	$	—		$	(81	)

(a)Included in other current liabilities in our consolidated balance sheets.

Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value



Balance sheet line item	December 31, 2016		December 31, 2015		Balance sheet line item	December 31, 2016			December 31, 2015
	(Millions)					(Millions)
Derivative assets not designated as hedging instruments:					Derivative liabilities not designated as hedging instruments:
Commodity derivatives:					Commodity derivatives:
Unrealized gains on derivative instruments — current	$	42	$	156	Unrealized losses on derivative instruments — current	$	(91	)	$	(69	)
Unrealized gains on derivative instruments — long-term	5		19		Unrealized losses on derivative instruments — long-term	(1		)	(12		)
Total	$	47	$	175	Total	$	(92	)	$	(81	)

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)

year ended December 31, 2016:



	Interest Rate Derivatives			Commodity Derivatives			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(3	)	$	(6	)	$	1	$	(8	)
Net deferred (losses) gains in AOCI (ending balance)	$	(3	)	$	(6	)	$	1	$	(8	)


(a)	Relates to Discovery, an unconsolidated affiliate.

The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the year ended December 31, 2015:



	Interest Rate Cash Flow Hedges			Commodity Cash Flow Hedges			Foreign Currency Cash Flow Hedges (a)		Total
	(Millions)
Net deferred (losses) gains in AOCI (beginning balance)	$	(4	)	$	(6	)	$	1	$	(9	)
Losses reclassified from AOCI to earnings — effective portion (b)	1			—			—		1
Net deferred losses in AOCI (ending balance)	$	(3	)	$	(6	)	$	1	$	(8	)


(a)	Relates to Discovery, an unconsolidated affiliate.


(b)	Included in interest expense in our consolidated statements of operations.

Schedule of Changes in Derivative Instruments Not Designated as Hedging Instruments

The following summarizes these amounts and the location within the consolidated statements of operations that such amounts are reflected:



		Year Ended December 31,
Derivatives: Statements of Operations Line Item		2016			2015		2014
	(Millions)
Realized gains		$	116		$	73	$	45
Unrealized (losses) gains		(139		)	46		43
Trading and marketing (losses) gains, net		$	(23	)	$	119	$	88

Schedule of Net Long or Short Positions Expected to be Realized



	December 31, 2016
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net (Short) Long Position (Bbls)		Net Long Position (MMBtu)
2017	(1,470,000	)	(44,981,850	)	(22,225,821	)	6,510,000
2018	(251,000	)	—		144,805		912,500
2019	(40,000	)	—		(2,203	)	—
2020	(50,000)		—		240,000		—



	December 31, 2015
	Crude Oil		Natural Gas		Natural Gas Liquids		Natural Gas Basis Swaps
Year of Expiration	Net Short Position (Bbls)		Net Short Position (MMBtu)		Net (Short) Long Position (Bbls)		Net Long Position (MMBtu)
2016	(1,566,672	)	(25,059,414	)	(23,575,094	)	2,207,500
2017	(237,000	)	(7,387,500	)	(2,082,157	)	4,050,000
2018	—		—		120,000		—

Partnership Equity and Distributions (Tables)

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Cash Distribution

The following table presents our cash distributions paid in 2016, 2015 and 2014:



Payment Date	Per Unit Distribution		Total Cash Distribution
	(Millions)
November 14, 2016	$	0.7800	$	120
August 12, 2016	$	0.7800	$	121
May 13, 2016	$	0.7800	$	121
February 12, 2016	$	0.7800	$	121
November 13, 2015	$	0.7800	$	120
August 14, 2015	$	0.7800	$	121
May 15, 2015	$	0.7800	$	121
February 13, 2015	$	0.7800	$	120
November 14, 2014	$	0.7700	$	117
August 14, 2014	$	0.7575	$	111
May 15, 2014	$	0.7450	$	106
February 14, 2014	$	0.7325	$	86

Equity-Based Compensation Equity-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Fair Value of Unvested Awards

The following table presents the fair value of unvested unit-based awards related to the strategic performance units and phantom units:



	Vesting Period (years)	Unrecognized Compensation Expense at December 31, 2016 (millions)		Estimated Forfeiture Rate	Weighted-Average Remaining Vesting (years)
DCP Midstream LTIP:
Strategic Performance Units (SPUs)	3	$	6	0%-11%	2
Phantom Units	1-3	$	5	0%-11%	2

Schedule of Award Activity

The following tables presents information related to SPUs:



	Units		Grant Date Weighted-Average Price Per Unit		Measurement Date Weighted-Average Price Per Unit
Outstanding at January 1, 2014	230,900		$	39.30
Granted	116,790		$	54.05
Forfeited	(13,828	)	$	40.75
Vested (a)	(114,499	)	$	37.72
Outstanding at December 31, 2014	219,363		$	47.89
Granted	111,930		$	43.25
Forfeited	(29,283	)	$	48.02
Vested (b)	(93,551	)	$	41.02
Outstanding at December 31, 2015	208,459		$	48.46
Granted	131,610		$	45.31
Forfeited	(8,463	)	$	46.27
Vested (c)	(98,295	)	$	54.05
Outstanding at December 31, 2016	233,311		$	44.41	$	45.86
Expected to vest	219,844		$	44.35	$	45.98

(a) The 2012 grants vested at 115%.

(b) The 2013 grants vested at 115%.

The following table presents information related to Phantom Units:



	Units		Grant Date Weighted-Average Price Per Unit		Measurement Date Weighted-Average Price Per Unit
Outstanding at January 1, 2014	207,522		$	40.18
Granted	122,650		$	53.73
Forfeited	(11,130	)	$	41.96
Vested	(147,840	)	$	42.10
Outstanding at December 31, 2014	171,202		$	48.11
Granted	147,540		$	47.84
Forfeited	(17,400	)	$	48.40
Vested	(96,974	)	$	44.00
Outstanding at December 31, 2015	204,368		$	49.85
Granted	132,870		$	45.33
Forfeited	(3,240	)	$	48.62
Vested	(126,681	)	$	50.13
Outstanding at December 31, 2016	207,317		$	46.80	$	45.97
Expected to vest	185,785		$	46.72	$	45.90

Schedule of Awards Vested

The following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related to the phantom units:



	Units	Fair Value of Units Vested		Unit-Based Liabilities Paid
		(millions)
Vested or paid in cash in 2014	147,840	$	5	$	5
Vested or paid in cash in 2015	96,974	$	3	$	5
Vested or paid in cash in 2016	126,681	$	4	$	5

The following table presents the fair value of units vested and the unit-based liabilities paid for unit-based awards related to the strategic performance units:



	Units	Fair Value of Units Vested		Unit-Based Liabilities Paid
		(millions)
Vested or paid in cash in 2014	114,499	$	7	$	8
Vested or paid in cash in 2015	93,551	$	4	$	7
Vested or paid in cash in 2016	98,295	$	7	$	4

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

Income tax (expense) benefit consists of the following:



	Year Ended December 31,
	2016			2015		2014
	(Millions)
Current:
Federal income tax expense	$	(19	)	$	—	$	—
State income tax expense	(2		)	—		(2		)
Deferred:
Federal income tax (expense) benefit	(22		)	97		—
State income tax (expense) benefit	(3		)	5		(9		)
Total income tax (expense) benefit	$	(46	)	$	102	$	(11	)

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

Deferred income tax assets and liabilities consisted of the following:



	December 31,
	2016			2015
	(Millions)
Deferred income tax assets:
Net operating loss	$	—		$	58
Total deferred income tax assets	—			58
Deferred income tax liabilities:
Property, plant and equipment and intangibles - federal	—			(35		)
Property, plant and equipment and intangibles - state	(28		)	(26		)
Total deferred income tax liabilities	(28		)	(61		)
Net deferred income tax liabilities	(28		)	(3		)

Deferred income tax assets, net - noncurrent	—			23
Deferred income tax liabilities, net - noncurrent	(28		)	(26		)
Net deferred income tax liabilities	$	(28	)	$	(3	)

Commitments and Contingent Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases

Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2016:



	(Millions)
2017	$	61
2018	37
2019	35
2020	29
2021	21
Thereafter	42
Total minimum rental payments	$	225

Business Segments (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Segment Information

Year Ended December 31, 2016:



	Gathering and Processing			Logistics and Marketing			Other			Eliminations			Total
	(Millions)
Total operating revenue	$	4,490		$	6,186		$	—		$	(3,783	)	$	6,893
Gross margin (a)	$	1,227		$	205		$	—		$	—		$	1,432
Operating and maintenance expense	(611		)	(43		)	(16		)	—			(670		)
Depreciation and amortization expense	(344		)	(15		)	(19		)	—			(378		)
General and administrative expense	(14		)	(9		)	(269		)	—			(292		)
Other income (expense), net	73			(5		)	(3		)	—			65
Earnings from unconsolidated affiliates	73			209			—			—			282
Interest expense, net	—			—			(321		)	—			(321		)
Gain on sale of assets, net	19			16			—			—			35
Restructuring costs	—			—			(13		)	—			(13		)
Income tax expense	—			—			(46		)	—			(46		)
Net income (loss)	$	423		$	358		$	(687	)	$	—		$	94
Net income attributable to non-controlling interests	(6		)	—			—			—			(6		)
Net income (loss) attributable to partners	$	417		$	358		$	(687	)	$	—		$	88
Non-cash derivative mark-to-market (b)	$	(119	)	$	(20	)	$	—		$	—		$	(139	)
Non-cash lower of cost or market adjustments	$	—		$	3		$	—		$	—		$	3
Capital expenditures	$	107		$	10		$	27		$	—		$	144
Investments in unconsolidated affiliates, net	$	1		$	52		$	—		$	—		$	53

Year Ended December 31, 2015:



	Gathering and Processing			Logistics and Marketing			Other			Eliminations			Total
	(Millions)
Total operating revenue	$	4,910		$	6,487		$	—		$	(3,967	)	$	7,430
Gross margin (a)	$	1,213		$	236		$	—		$	—		$	1,449
Operating and maintenance expense	(668		)	(49		)	(15		)	—			(732		)
Depreciation and amortization expense	(343		)	(16		)	(18		)	—			(377		)
General and administrative expense	(22		)	(11		)	(248		)	—			(281		)
Other expense, net	(1		)	(8		)	(1		)	—			(10		)
Asset impairment	(876		)	(9		)	(27		)	—			(912		)
Earnings from unconsolidated affiliates	54			130			—			—			184
Interest expense, net	—			—			(320		)	—			(320		)
Gain on sale of assets, net	42			—			—			—			42
Restructuring costs	—			—			(11		)	—			(11		)
Income tax benefit	—			—			102			—			102
Net income (loss)	$	(601	)	$	273		$	(538	)	$	—		$	(866	)
Net income attributable to non-controlling interests	(5		)	—			—			—			(5		)
Net income (loss) attributable to partners	$	(606	)	$	273		$	(538	)	$	—		$	(871	)
Non-cash derivative mark-to-market (b)	$	47		$	(1	)	$	—		$	—		$	46
Non-cash lower of cost or market adjustments	$	—		$	8		$	—		$	—		$	8
Capital expenditures	$	729		$	52		$	30		$	—		$	811
Investments in unconsolidated affiliates, net	$	15		$	49		$	—		$	—		$	64

Year Ended December 31, 2014:



	Gathering and Processing			Logistics and Marketing			Other			Eliminations			Total
	(Millions)
Total operating revenue	$	9,873		$	12,649		$	—		$	(8,497	)	$	14,025
Gross margin (a)	$	1,971		$	226		$	—		$	—		$	2,197
Operating and maintenance expense	(725		)	(44		)	(4		)	—			(773		)
Depreciation and amortization expense	(315		)	(17		)	(16		)	—			(348		)
General and administrative expense	(27		)	(14		)	(236		)	—			(277		)
Other expense, net	(5		)	—			(2		)	—			(7		)
Asset impairment	(18		)	—			—			—			(18		)
Earnings from unconsolidated affiliates	5			77			—			—			82
Interest expense, net	—			—			(287		)	—			(287		)
Loss on sale of assets, net	(7		)	—			—			—			(7		)
Income tax expense	—			—			(11		)	—			(11		)
Net income (loss)	$	879		$	228		$	(556	)	$	—		$	551
Net income attributable to non-controlling interests	(4		)	—			—			—			(4		)
Net income (loss) attributable to partners	$	875		$	228		$	(556	)	$	—		$	547
Non-cash derivative mark-to-market (b)	$	39		$	4		$	—		$	—		$	43
Non-cash lower of cost or market adjustments	$	—		$	24		$	—		$	—		$	24
Capital expenditures	$	1,272		$	62		$	50		$	—		$	1,384
Investments in unconsolidated affiliates, net	$	75		$	86		$	—		$	—		$	161



	December 31,
	2016		2015
	(Millions)
Segment long-term assets:
Gathering and Processing	$	9,053	$	9,431
Logistics and Marketing	3,278		3,339
Other (c)	286		311
Total long-term assets	12,617		13,081
Current assets	994		804
Total assets	$	13,611	$	13,885

(a)


(b)	Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts.


(c)	Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets.

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Elements [Abstract]

Summary of Supplemental Cash Flow Information



	Year Ended December 31,
	2016			2015			2014
	(Millions)
Cash paid for interest:
Cash paid for interest, net of amounts capitalized	$	306		$	293		$	274
Cash paid for income taxes, net of income tax refunds	$	2		$	3		$	4
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts payable	$	27		$	35		$	145
Other non-cash changes in property, plant and equipment	$	(3	)	$	(19	)	$	27
Contribution of assets from our predecessor	$	—		$	1,500		$	—

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information

Our consolidated results of operations by quarter for the years ended December 31, 2016 and 2015 were as follows (millions, except per unit amounts):



2016	First			Second			Third			Fourth			Year Ended December 31, 2016
Total operating revenues	$	1,464		$	1,623		$	1,823		$	1,983		$	6,893
Operating income (loss)	$	80		$	(12	)	$	92		$	19		$	179
Net income (loss)	$	65		$	(21	)	$	89		$	(39	)	$	94
Net income attributable to non-controlling interests	$	—		$	(1	)	$	—		$	(5	)	$	(6	)
Net income attributable to partners	$	65		$	(22	)	$	89		$	(44	)	$	88
Net loss attributable to predecessor operations	$	(7	)	$	(67	)	$	(31	)	$	(119	)	$	(224	)
Net income allocable to limited partners	$	41		$	14		$	89		$	44		$	188
Basic and diluted net income per limited partner unit	$	0.36		$	0.12		$	0.78		$	0.38		$	1.64



2015	First			Second			Third			Fourth			Year Ended December 31, 2015
Total operating revenues	$	2,020		$	1,849		$	1,870		$	1,691		$	7,430
Operating income (loss)	$	40		$	(463	)	$	57		$	(466	)	$	(832	)
Net (loss) income	$	(17	)	$	(491	)	$	24		$	(382	)	$	(866	)
Net income attributable to non-controlling interests	$	—		$	—		$	(1	)	$	(4	)	$	(5	)
Net income attributable to partners	$	(17	)	$	(491	)	$	23		$	(386	)	$	(871	)
Net loss attributable to predecessor operations	$	(86	)	$	(489	)	$	(48	)	$	(476	)	$	(1,099	)
Net income (loss) allocable to limited partners	$	38		$	(33	)	$	40		$	59		$	104
Basic and diluted net income (loss) per limited partner unit	$	0.33		$	(0.29	)	$	0.35		$	0.51		$	0.91

Supplementary Information - Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2016

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Consolidating Balance Sheets



	Condensed Consolidating Balance Sheet
	December 31, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	1		$	—		$	1
Accounts receivable, net	—		—			792			—			792
Inventories	—		—			72			—			72
Other	—		—			129			—			129
Total current assets	—		—			994			—			994
Property, plant and equipment, net	—		—			9,069			—			9,069
Goodwill and intangible assets, net	—		—			373			—			373
Advances receivable — consolidated subsidiaries	2,953		2,760			—			(5,713		)	—
Investments in consolidated subsidiaries	3,868		6,587			—			(10,455		)	—
Investments in unconsolidated affiliates	—		—			2,969			—			2,969
Other long-term assets	—		—			206			—			206
Total assets	$	6,821	$	9,347		$	13,611		$	(16,168	)	$	13,611
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	72		$	1,051		$	—		$	1,123
Current maturities of long-term debt	—		500			—			—			500
Advances payable — consolidated subsidiaries	—		—			5,713			(5,713		)	—
Long-term debt	—		4,907			—			—			4,907
Other long-term liabilities	—		—			228			—			228
Total liabilities	—		5,479			6,992			(5,713		)	6,758
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	6,821		3,871			6,592			(10,455		)	6,829
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	6,821		3,868			6,587			(10,455		)	6,821
Non-controlling interests	—		—			32			—			32
Total equity	6,821		3,868			6,619			(10,455		)	6,853
Total liabilities and equity	$	6,821	$	9,347		$	13,611		$	(16,168	)	$	13,611



	Condensed Consolidating Balance Sheet
	December 31, 2015
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—		$	3		$	—		$	3
Accounts receivable, net	—		—			544			—			544
Inventories	—		—			51			—			51
Other	—		—			206			—			206
Total current assets	—		—			804			—			804
Property, plant and equipment, net	—		—			9,428			—			9,428
Goodwill and intangible assets, net	—		—			391			—			391
Advances receivable — consolidated subsidiaries	3,436		3,353			—			(6,789		)	—
Investments in consolidated subsidiaries	3,623		6,011			—			(9,634		)	—
Investments in unconsolidated affiliates	—		—			2,992			—			2,992
Other long-term assets	—		—			270			—			270
Total assets	$	7,059	$	9,364		$	13,885		$	(16,423	)	$	13,885
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	$	—	$	72		$	827		$	—		$	899
Advances payable — consolidated subsidiaries			—			6,789			(6,789		)	—
Long-term debt	—		5,669			—			—			5,669
Other long-term liabilities	—		—			225			—			225
Total liabilities	—		5,741			7,841			(6,789		)	6,793
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity	7,059		3,626			6,016			(9,634		)	7,067
Accumulated other comprehensive loss	—		(3		)	(5		)	—			(8		)
Total partners’ equity	7,059		3,623			6,011			(9,634		)	7,059
Non-controlling interests	—		—			33			—			33
Total equity	7,059		3,623			6,044			(9,634		)	7,092
Total liabilities and equity	$	7,059	$	9,364		$	13,885		$	(16,423	)	$	13,885

Condensed Income Statement



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2014
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	—	$	—		$	13,420		$	—		$	13,420
Transportation, processing and other	—		—			517			—			517
Trading and marketing gains, net	—		—			88			—			88
Total operating revenues	—		—			14,025			—			14,025
Operating costs and expenses:
Purchases of natural gas and NGLs	—		—			11,828			—			11,828
Operating and maintenance expense	—		—			773			—			773
Depreciation and amortization expense	—		—			348			—			348
General and administrative expense	—		—			277			—			277
Asset impairments	—		—			18			—			18
Other expense, net	—		—			7			—			7
Loss on sale of assets, net	—		—			7			—			7
Total operating costs and expenses	—		—			13,258			—			13,258
Operating income	—		—			767			—			767
Interest expense, net	—		(287		)	—			—			(287		)
Earnings from unconsolidated affiliates	—		—			82			—			82
Income from consolidated subsidiaries	547		834			—			(1,381		)	—
Income before income taxes	547		547			849			(1,381		)	562
Income tax expense	—		—			(11		)	—			(11		)
Net income	547		547			838			(1,381		)	551
Net income attributable to non-controlling interests	—		—			(4		)	—			(4		)
Net income attributable to partners	$	547	$	547		$	834		$	(1,381	)	$	547



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2016
	Parent Guarantor		Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	—	$	—		$	6,269		$	—		$	6,269
Transportation, processing and other	—		—			647			—			647
Trading and marketing losses, net	—		—			(23		)	—			(23		)
Total operating revenues	—		—			6,893			—			6,893
Operating costs and expenses:
Purchases of natural gas and NGLs	—		—			5,461			—			5,461
Operating and maintenance expense	—		—			670			—			670
Depreciation and amortization expense	—		—			378			—			378
General and administrative expense	—		—			292			—			292
Other income, net	—		—			(65		)	—			(65		)
Restructuring costs	—		—			13						13
Gain on sale of assets, net	—		—			(35		)	—			(35		)
Total operating costs and expenses	—		—			6,714			—			6,714
Operating income	—		—			179			—			179
Interest expense, net	—		(321		)	—			—			(321		)
Income from consolidated subsidiaries	88		409			—			(497		)	—
Earnings from unconsolidated affiliates	—		—			282			—			282
Income before income taxes	88		88			461			(497		)	140
Income tax expense	—		—			(46		)	—			(46		)
Net income	88		88			415			(497		)	94
Net income attributable to non-controlling interests	—		—			(6		)	—			(6		)
Net income attributable to partners	$	88	$	88		$	409		$	(497	)	$	88



	Condensed Consolidating Statement of Operations
	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
	(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	—		$	—		$	6,779		$	—	$	6,779
Transportation, processing and other	—			—			532			—		532
Trading and marketing gains, net	—			—			119			—		119
Total operating revenues	—			—			7,430			—		7,430
Operating costs and expenses:
Purchases of natural gas and NGLs	—			—			5,981			—		5,981
Operating and maintenance expense	—			—			732			—		732
Depreciation and amortization expense	—			—			377			—		377
General and administrative expense	—			—			281			—		281
Asset impairments	—			—			912			—		912
Other expense, net	—			—			10			—		10
Restructuring costs	—			—			11			—		11
Gain on sale of assets, net	—			—			(42		)	—		(42		)
Total operating costs and expenses	—			—			8,262			—		8,262
Operating loss	—			—			(832		)	—		(832		)
Interest expense, net	—			(320		)	—			—		(320		)
Loss from consolidated subsidiaries	(871		)	(551		)	—			1,422		—
Earnings from unconsolidated affiliates	—			—			184			—		184
Loss before income taxes	(871		)	(871		)	(648		)	1,422		(968		)
Income tax benefit	—			—			102			—		102
Net loss	(871		)	(871		)	(546		)	1,422		(866		)
Net income attributable to non-controlling interests	—			—			(5		)	—		(5		)
Net loss attributable to partners	$	(871	)	$	(871	)	$	(551	)	$	1,422	$	(871	)

Condensed Statement of Comprehensive Income



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net loss	$	(871	)	$	(871	)	$	(546	)	$	1,422		$	(866	)
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—			1			—			—			1
Other comprehensive income from consolidated subsidiaries	1			—			—			(1		)	—
Total other comprehensive income	1			1			—			(1		)	1
Total comprehensive loss	(870		)	(870		)	(546		)	1,421			(865		)
Total comprehensive loss attributable to non-controlling interests	—			—			(5		)	—			(5		)
Total comprehensive loss attributable to partners	$	(870	)	$	(870	)	$	(551	)	$	1,421		$	(870	)



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2016
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	88	$	88	$	415		$	(497	)	$	94
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		—		—			—			—
Other comprehensive income from consolidated subsidiaries	—		—		—			—			—
Total other comprehensive income	—		—		—			—			—
Total comprehensive income	88		88		415			(497		)	94
Total comprehensive income attributable to non-controlling interests	—		—		(6		)	—			(6		)
Total comprehensive income attributable to partners	$	88	$	88	$	409		$	(497	)	$	88



	Condensed Consolidating Statement of Comprehensive Income
	Year Ended December 31, 2014
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
Net income	$	547	$	547	$	838		$	(1,381	)	$	551
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings	—		2		—			—			2
Other comprehensive income from consolidated subsidiaries	2		—		—			(2		)	—
Total other comprehensive income	2		2		—			(2		)	2
Total comprehensive income	549		549		838			(1,383		)	553
Total comprehensive income attributable to non-controlling interests	—		—		(4		)	—			(4		)
Total comprehensive income attributable to partners	$	549	$	549	$	834		$	(1,383	)	$	549

Condensed Consolidating Statements of Cash Flows



	Condensed Consolidating Statement of Cash Flows
	Year Ended December 31, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(305	)	$	950		$	—		$	645
INVESTING ACTIVITIES:
Intercompany transfers	483			585			—			(1,068		)	—
Capital expenditures	—			—			(144		)	—			(144		)
Investments in unconsolidated affiliates, net	—			—			(53		)	—			(53		)
Proceeds from sale of assets	—			—			163			—			163
Net cash provided by (used in) investing activities	483			585			(34		)	(1,068		)	(34		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(1,068		)	1,068			—
Proceeds from long-term debt	—			3,353			—			—			3,353
Payments of long-term debt	—			(3,628		)	—			—			(3,628		)
Payments of deferred financing costs	—			(5		)	—			—			(5		)
Net change in advances to predecessor from DCP Midstream, LLC	—			—			157			—			157
Distributions to limited partners and general partner	(483		)	—			—			—			(483		)
Distributions to non-controlling interests	—			—			(7		)	—			(7		)
Net cash used in financing activities	(483		)	(280		)	(918		)	1,068			(613		)
Net change in cash and cash equivalents	—			—			(2		)	—			(2		)
Cash and cash equivalents, beginning of period	—			—			3			—			3
Cash and cash equivalents, end of period	$	—		$	—		$	1		$	—		$	1



	Condensed Consolidating Statements of Cash Flows
	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(311	)	$	753		$	—		$	442
INVESTING ACTIVITIES:
Intercompany transfers	(1,049		)	1,283			—			(234		)	—
Capital expenditures	—			—			(811		)	—			(811		)
Investments in unconsolidated affiliates, net	—			—			(64		)	—			(64		)
Proceeds from sale of assets	—			—			164			—			164
Net cash (used in) provided by investing activities	(1,049		)	1,283			(711		)	(234		)	(711		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			(234		)	234			—
Proceeds from long-term debt	—			7,216			—			—			7,216
Payments of long-term debt	—			(7,196		)	—			—			(7,196		)
Payments of commercial paper, net	—			(1,012		)	—			—			(1,012		)
Payment of deferred financing costs	—			(4		)	—			—			(4		)
Proceeds from issuance of common units, net of offering costs	31			—			—			—			31
Net change in advances to predecessor from DCP Midstream, LLC	1,500			—			197			—			1,697
Distributions to limited partners and general partner	(482		)	—			—			—			(482		)
Distributions to non-controlling interests	—						(5		)	—			(5		)
Net cash provided by (used in) financing activities	1,049			(996		)	(42		)	234			245
Net change in cash and cash equivalents	—			(24		)	—			—			(24		)
Cash and cash equivalents, beginning of period	—			24			3			—			27
Cash and cash equivalents, end of period	$	—		$	—		$	3		$	—		$	3



	Condensed Consolidating Statements of Cash Flows
	Year Ended December 31, 2014
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
	(Millions)
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$	—		$	(271	)	$	1,088		$	—		$	817
INVESTING ACTIVITIES:
Intercompany transfers	(581		)	(141		)	—			722			—
Capital expenditures	—			—			(1,384		)	—			(1,384		)
Investments in unconsolidated affiliates, net	—			—			(161		)	—			(161		)
Proceeds from sale of assets	—			—			30			—			30
Net cash used in investing activities	(581		)	(141		)	(1,515		)	722			(1,515		)
FINANCING ACTIVITIES:
Intercompany transfers	—			—			722			(722		)	—
Proceeds from long-term debt	—			719			—			—			719
Payments of issuance of commercial paper, net	—			(288		)	—			—			(288		)
Payment of deferred financing costs	—			(12		)	—			—			(12		)
Proceeds from issuance of common units, net of offering costs	1,001			—			—			—			1,001
Distributions to limited partners and general partner	(420		)	—			—			—			(420		)
Distributions to non-controlling interests	—			—			(5		)	—			(5		)
Net change in advances to predecessor from DCP Midstream, LLC	—			—			(301		)	—			(301		)
Net cash provided by financing activities	581			419			416			(722		)	694
Net change in cash and cash equivalents	—			7			(11		)	—			(4		)
Cash and cash equivalents, beginning of year	—			17			14			—			31
Cash and cash equivalents, end of year	$	—		$	24		$	3		$	—		$	27

Description of Business and Basis of Presentation - Additional Information (Detail)		12 Months Ended
	Jan. 01, 2017	Dec. 31, 2016
Investments in Greater Than 20%
Business Acquisition [Line Items]
Equity method investment ownership (as percent)		20.00%
Investments in Less Than 20%
Business Acquisition [Line Items]
Equity method investment ownership (as percent)		20.00%
DCP Midstream GP, LLC \| DCP Midstream LLC
Business Acquisition [Line Items]
Ownership interest percentage by parent		100.00%
DCP Midstream LLC \| Phillips 66
Business Acquisition [Line Items]
Ownership interest percentage by parent		50.00%
DCP Midstream LLC \| Enbridge
Business Acquisition [Line Items]
Ownership interest percentage by parent		50.00%
DCP Midstream LP \| DCP Midstream LLC
Business Acquisition [Line Items]
Ownership interest percentage by parent		21.40%
DCP Midstream LP \| DCP Midstream LLC \| Subsequent Event
Business Acquisition [Line Items]
Ownership interest percentage by parent	38.10%

Summary of Significant Accounting Policies (Details)	Dec. 31, 2016
Investments in Greater Than 20%
Summary Of Significant Accounting Policies [Line Items]
Equity method investment ownership (as percent)	20.00%
Investments in Less Than 20%
Summary Of Significant Accounting Policies [Line Items]
Equity method investment ownership (as percent)	20.00%

Acquisitions - Additional Information (Detail) $ in Millions				1 Months Ended	12 Months Ended
	Jan. 01, 2017 USD ($) shares	Jan. 01, 2015 USD ($)	Mar. 28, 2014 MMcf	Mar. 31, 2014 USD ($) shares	Dec. 31, 2016 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Cash acquired	$ 424
Debt assumed	3,150
Payment for incentive fee	$ 100
Issuance of units (in shares)						$ 225
Excess purchase price over carrying value of acquired net assets						$ 178
Senior Notes \| Issued March, 2014, interest at 5.600% payable semi-annually, due April, 2044
Business Acquisition [Line Items]
Stated interest rate					5.60%
Debt term					30 years
Senior Notes \| Revolving credit agreement, weighted-average variable interest rate of 2.014% and 1.572%, as of December 31, 2016 and December 31, 2015, respectively, due May 2019 \| Issued March, 2014, interest at 2.700% payable semi-annually, due April, 2019
Business Acquisition [Line Items]
Stated interest rate					2.70%
Debt term					5 years
Panola Pipeline Company, LLC
Business Acquisition [Line Items]
Percentage of interest acquired		15.00%
Aggregate consideration for acquisition		$ 1
Anticipated consideration to be paid for acquisition		$ 26
DCP Sand Hills Pipeline, LLC
Business Acquisition [Line Items]
Percentage of interest acquired				33.33%
DCP Southern Hills Pipeline, LLC
Business Acquisition [Line Items]
Percentage of interest acquired				33.33%
Eagle Ford System
Business Acquisition [Line Items]
Percentage of interest acquired				20.00%
Lucerne 1
Business Acquisition [Line Items]
Capacity of plants or pipelines per day \| MMcf			35
Lucerne 2
Business Acquisition [Line Items]
Capacity of plants or pipelines per day \| MMcf			200
March 2014 Transactions
Business Acquisition [Line Items]
Aggregate consideration for acquisition				$ 1,220
Issuance of units (in shares)				$ 225
Excess purchase price over carrying value of acquired net assets					$ 178
Common Units
Business Acquisition [Line Items]
Equity interest issued (in shares) \| shares	28,552,480
Common Units \| DCP Sand Hills Pipeline, LLC
Business Acquisition [Line Items]
Equity interest issued (in shares) \| shares				1,399,116
Common Units \| DCP Southern Hills Pipeline, LLC
Business Acquisition [Line Items]
Equity interest issued (in shares) \| shares				2,098,674
Common Units \| Eagle Ford System
Business Acquisition [Line Items]
Equity interest issued (in shares) \| shares				999,368
Common Units \| March 2014 Transactions
Business Acquisition [Line Items]
Equity interest issued (in shares) \| shares				14,375,000
General Partner Units
Business Acquisition [Line Items]
Equity interest issued (in shares) \| shares	2,550,644

Dispositions (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
Dispositions (Details) - USD ($) $ in Millions	Aug. 31, 2014	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	May 31, 2016	Jul. 31, 2015	May 31, 2015	Jan. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal		$ 35	$ 35	$ 42	$ (7)
Northern Louisiana
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity interest disposed						100.00%
Consideration transferred						$ 160
Gain (loss) on disposal		$ 41
Non-Core Gas Processing Plant
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred							$ 120
Gain (loss) on disposal				59
Benedum
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred								$ 21
Gain (loss) on disposal				27
Goodwill associated with disposal				2
Dover-Hennessey
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity interest disposed									44.00%
Consideration transferred									$ 29
Gain (loss) on disposal				$ 10
Main Pass
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity interest disposed	66.67%
Consideration transferred	$ 14
Gain (loss) on disposal					$ 6
Selling costs	$ 3
Gas Processing Plant \| Benedum
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity interest disposed								33.00%
Gathering System \| Benedum
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity interest disposed								100.00%

Agreements and Transactions with Affiliates - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Affiliated Entity
Related Party Transaction [Line Items]
Terms of agreement	15 years
DCP Sand Hills Pipeline, LLC \| Affiliated Entity
Related Party Transaction [Line Items]
Terms of agreement	15 years
Annual Service Fee	$ 5
DCP Southern Hills Pipeline, LLC \| Affiliated Entity
Related Party Transaction [Line Items]
Terms of agreement	15 years
Annual Service Fee	$ 5
Front Range Pipeline \| Affiliated Entity
Related Party Transaction [Line Items]
Terms of agreement	15 years
Texas Express Pipeline LLC \| Affiliated Entity
Related Party Transaction [Line Items]
Terms of agreement	15 years
Phillips 66 \| Chevron Phillips Chemical LLC \| Affiliated Entity
Related Party Transaction [Line Items]
Equity method investment ownership (as percent)	50.00%
Natural Gas Liquids \| Affiliated Entity
Related Party Transaction [Line Items]
Percent of NGL production committed	27.00%
Operating and Maintenance Expense
Related Party Transaction [Line Items]
Employee related costs	$ 206	$ 224	$ 225
General and Administrative Expense and Restructuring Costs
Related Party Transaction [Line Items]
Employee related costs	$ 197	$ 194	$ 184

Agreements and Transactions with Affiliates - Transactions with Affiliates (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate to affiliates	$ 6,269	$ 6,779	$ 13,420
Purchases of natural gas and NGLs from affiliates	5,461	5,981	11,828
Operating and maintenance expense	670	732	773
Transportation, storage and processing to affiliates	647	532	517
Affiliated Entity \| Phillips 66
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate to affiliates	909	695	1,960
Purchases of natural gas and NGLs from affiliates	18	0	11
Operating and maintenance expense	2	4	3
Affiliated Entity \| Enbridge
Related Party Transaction [Line Items]
Purchases of natural gas and NGLs from affiliates	33	50	88
Operating and maintenance expense	4	6	10
Transportation, storage and processing to affiliates	0	0	14
Affiliated Entity \| Unconsolidated Affiliates
Related Party Transaction [Line Items]
Sales of natural gas, NGLs and condensate to affiliates	43	70	70
Purchases of natural gas and NGLs from affiliates	432	368	366
Transportation, storage and processing to affiliates	$ 5	$ 3	$ 12

Agreements and Transactions with Affiliates - Balances with Affiliates (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Accounts receivable	$ 134	$ 75
Accounts payable	48	40
Phillips 66
Related Party Transaction [Line Items]
Accounts receivable	115	54
Accounts payable	4	3
Other assets	2	1
Enbridge
Related Party Transaction [Line Items]
Accounts receivable	1	0
Accounts payable	3	4
Other assets	1	1
Other liabilities	1	0
Unconsolidated Affiliates
Related Party Transaction [Line Items]
Accounts receivable	18	21
Accounts payable	41	33
Other assets	$ 5	$ 31

Inventories - Schedule of Inventories (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Components Of Inventory [Line Items]
Total inventories	$ 72	$ 51
Natural Gas
Components Of Inventory [Line Items]
Total inventories	28	29
Natural Gas Liquids
Components Of Inventory [Line Items]
Total inventories	$ 44	$ 22

Inventories - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
Non-cash lower of cost or market adjustments	$ 3	$ 8	$ 24

Property, Plant and Equipment - Classification of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 14,367	$ 14,598
Accumulated depreciation	(5,298)	(5,170)
Property, plant and equipment, net	9,069	9,428
Interest Costs Capitalized	1	32	$ 34
Depreciation	366	358	$ 327
Gathering and transmission systems
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 8,560	8,815
Gathering and transmission systems \| Minimum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	20 years
Gathering and transmission systems \| Maximum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	50 years
Processing, storage, and terminal facilities
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 5,134	5,102
Processing, storage, and terminal facilities \| Minimum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	35 years
Processing, storage, and terminal facilities \| Maximum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	60 years
Other
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 502	485
Other \| Minimum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	3 years
Other \| Maximum
Property, Plant and Equipment [Line Items]
Depreciable life of property, plant and equipment	30 years
Construction work in progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 171	$ 196

Property, Plant and Equipment - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation [Roll Forward]
Balance, beginning of period	$ 120	$ 117
Accretion expense	7	7	$ 6
Revisions in estimated cash flows	(3)	(4)
Balance, end of period	$ 124	$ 120	$ 117

Goodwill and Intangible Assets Schedule of Goodwill (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Roll Forward]
Balance, beginning of period			$ 242	$ 704
Impairment			0	(460)
Dispositions			(6)	(2)
Balance, end of period			236	242
Mid-Continent And Permian
Goodwill [Roll Forward]
Impairment		$ (378)
Natural Gas Services
Goodwill [Roll Forward]
Impairment	$ (33)	$ (49)
Gathering and Processing
Goodwill [Roll Forward]
Balance, beginning of period			170	632
Impairment			0	(460)
Dispositions			(6)	(2)
Balance, end of period			164	170
Logistics and Marketing
Goodwill [Roll Forward]
Balance, beginning of period			72	72
Impairment			0	0
Dispositions			0	0
Balance, end of period			$ 72	$ 72

Goodwill and Intangible Assets Schedule of Finite-Lived Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Gross carrying amount			$ 410
Accumulated amortization	$ (151)	$ (139)
Accumulated impairment	(122)	(122)
Intangible assets, net	137	149
Amortization of Intangible Assets	$ 12	$ 19	$ 21

Goodwill and Intangible Assets Finite-Lived Intangible Assets, Future Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets [Line Items]
2017	$ 11
2018	11
2019	11
2020	11
2021	11
Thereafter	82
Intangible assets, net	$ 137	$ 149
Minimum
Finite-Lived Intangible Assets [Line Items]
Remaining amortization period	2 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Remaining amortization period	19 years
Weighted Average
Finite-Lived Intangible Assets [Line Items]
Remaining amortization period	14 years

Investments In Unconsolidated Affiliates (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Investments in and Advances to Affiliates [Line Items]
Investments in unconsolidated affiliates	$ 2,969	$ 2,992
DCP Sand Hills Pipeline, LLC
Investments in and Advances to Affiliates [Line Items]
Equity method investment ownership (as percent)	66.67%
Investments in unconsolidated affiliates	$ 1,507	1,492
DCP Southern Hills Pipeline, LLC
Investments in and Advances to Affiliates [Line Items]
Equity method investment ownership (as percent)	66.67%
Investments in unconsolidated affiliates	$ 754	764
Discovery Producer Services LLC
Investments in and Advances to Affiliates [Line Items]
Equity method investment ownership (as percent)	40.00%
Investments in unconsolidated affiliates	$ 385	405
Front Range Pipeline LLC
Investments in and Advances to Affiliates [Line Items]
Equity method investment ownership (as percent)	33.33%
Investments in unconsolidated affiliates	$ 165	170
Texas Express Pipeline LLC
Investments in and Advances to Affiliates [Line Items]
Equity method investment ownership (as percent)	10.00%
Investments in unconsolidated affiliates	$ 93	96
Panola Pipeline Company, LLC
Investments in and Advances to Affiliates [Line Items]
Equity method investment ownership (as percent)	15.00%
Investments in unconsolidated affiliates	$ 25	19
Mont Belvieu Enterprise Fractionator
Investments in and Advances to Affiliates [Line Items]
Equity method investment ownership (as percent)	12.50%
Investments in unconsolidated affiliates	$ 23	25
Mont Belvieu 1 Fractionator
Investments in and Advances to Affiliates [Line Items]
Equity method investment ownership (as percent)	20.00%
Investments in unconsolidated affiliates	$ 10	11
Other
Investments in and Advances to Affiliates [Line Items]
Investments in unconsolidated affiliates	$ 7	$ 10

Investments In Unconsolidated Affiliates - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
DCP Sand Hills Pipeline, LLC
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	$ 662	$ 677
DCP Southern Hills Pipeline, LLC
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	148	152
Discovery Producer Services LLC
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	20	24
Front Range Pipeline LLC
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	5	5
Texas Express Pipeline LLC
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	3	3
Mont Belvieu 1 Fractionator
Investments in and Advances to Affiliates [Line Items]
Carrying amount of the investment and the underlying equity (deficit)	$ 2	$ 3

Investments in Unconsolidated Affiliates - Earnings from Investments in Unconsolidated Affiliates (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	$ 282	$ 184	$ 82
DCP Sand Hills Pipeline, LLC
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	110	63	26
Mont Belvieu 1 Fractionator
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	9	9	12
DCP Southern Hills Pipeline, LLC
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	44	18	15
Mont Belvieu Enterprise Fractionator
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	16	15	17
Discovery Producer Services LLC
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	73	54	7
Texas Express Pipeline LLC
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	9	8	3
Front Range Pipeline LLC
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	19	17	2
Panola Pipeline Company, LLC
Investments in and Advances to Affiliates [Line Items]
Earnings from unconsolidated affiliates	$ 2	$ 0	$ 0

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Statement of Operations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Operating revenue	$ 1,311	$ 1,142	$ 859
Operating expenses	539	541	503
Net income	$ 768	$ 600	$ 354

Investments in Unconsolidated Affiliates - Equity Method Investment Summarized Financial Information, Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$ 232	$ 240
Long-term assets	5,274	5,224
Current liabilities	(156)	(167)
Long-term liabilities	(205)	(230)
Net assets	$ 5,145	$ 5,067

Fair Value Measurement - Financial Instruments Carried at Fair Value (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments	$ 0	$ 2
Long-Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments	0	8
Commodity Derivative \| Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	42	156
Commodity Derivative \| Long-Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	5	19
Commodity Derivative \| Current Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(91)	(69)
Commodity Derivative \| Long-Term Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(1)	(12)
Level 1 \| Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments	0	2
Level 1 \| Long-Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments	0	8
Level 1 \| Commodity Derivative \| Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	5	23
Level 1 \| Commodity Derivative \| Long-Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	0	3
Level 1 \| Commodity Derivative \| Current Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(11)	(16)
Level 1 \| Commodity Derivative \| Long-Term Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(1)	(1)
Level 2 \| Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments	0	0
Level 2 \| Long-Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments	0	0
Level 2 \| Commodity Derivative \| Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	28	98
Level 2 \| Commodity Derivative \| Long-Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	0	12
Level 2 \| Commodity Derivative \| Current Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(57)	(30)
Level 2 \| Commodity Derivative \| Long-Term Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	0	(5)
Level 3 \| Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments	0	0
Level 3 \| Long-Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments	0	0
Level 3 \| Commodity Derivative \| Current Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	9	35
Level 3 \| Commodity Derivative \| Long-Term Assets
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	5	4
Level 3 \| Commodity Derivative \| Current Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	(23)	(23)
Level 3 \| Commodity Derivative \| Long-Term Liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivatives	$ 0	$ (6)

Fair Value Measurement - Condensed Consolidated Balance Sheets for Derivative Financial Instruments (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 35	$ 23
Net realized and unrealized gains (losses) included in earnings	3	(82)
Transfers out of Level 3		0
Settlements	(29)	(25)
Purchases		119
Ending balance	9	35
Net unrealized gains still held included in earnings	9	(84)
Long-Term Assets
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	4	3
Net realized and unrealized gains (losses) included in earnings	1	1
Transfers out of Level 3		0
Settlements	0	0
Purchases		0
Ending balance	5	4
Net unrealized gains still held included in earnings	3	1
Current Liabilities
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(23)	(45)
Net realized and unrealized (losses) gains included in earnings	(15)	(29)
Transfers out of Level 3		1
Settlements	15	50
Purchases		0
Ending balance	(23)	(23)
Net unrealized gains (losses) still held included in earnings	(23)	(23)
Long-Term Liabilities
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(6)	(12)
Net realized and unrealized (losses) gains included in earnings	6	6
Transfers out of Level 3		0
Settlements	0	0
Purchases		0
Ending balance	0	(6)
Net unrealized gains (losses) still held included in earnings	$ 6	$ 4

Fair Value Measurement - Schedule of Valuation Processes (Detail) - Level 3 - Market Approach Valuation Technique - Natural Gas Liquids $ in Millions	Dec. 31, 2016 USD ($) $ / Gallon
Derivative Financial Instruments, Liabilities
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Fair Value, Liabilities \| $	$ 23
Derivative Financial Instruments, Liabilities \| Minimum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.25
Derivative Financial Instruments, Liabilities \| Maximum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	1.23
Derivative Financial Instruments, Assets
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Fair Value, Assets \| $	$ 14
Derivative Financial Instruments, Assets \| Minimum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	0.25
Derivative Financial Instruments, Assets \| Maximum
Fair Value Inputs Assets And Liabilities Quantitative Information [Line Items]
Forward Curve Range	1.20

Fair Value Measurement - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Carrying Amount	$ 5,430	$ 5,704
Fair Value	$ 5,395	$ 4,754

Debt - Schedule of Long-Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Fair value adjustments related to interest rate swap fair value hedges	$ 24	$ 26
Unamortized issuance costs	(23)	(35)
Unamortized discount	(14)	(18)
Total debt	5,407	5,669
Current maturities of long-term debt	500	0
Total long-term debt	4,907	5,669
Revolving credit agreement terminated December, 2016, weighted average interest rate of 2.930% at December 31, 2015
Line of Credit Facility [Line Items]
Credit facility issued amount	$ 0	96
Weighted average variable interest rate	2.93%
Revolving credit agreement, weighted-average variable interest rate of 2.014% and 1.572%, as of December 31, 2016 and December 31, 2015, respectively, due May 2019
Line of Credit Facility [Line Items]
Credit facility issued amount	$ 195	$ 375
Weighted average variable interest rate	1.572%	2.014%
Senior Notes \| Issued November, 2012, interest at 2.500% payable semi-annually, due December, 2017
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 500	$ 500
Stated interest rate	2.50%
Senior Notes \| Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a)
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 450	450
Stated interest rate	9.75%
Senior Notes \| Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a)
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 600	600
Stated interest rate	5.35%
Senior Notes \| Issued September 2011, interest at 4.750% payable semiannually, due September 2021
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 500	500
Stated interest rate	4.75%
Senior Notes \| Issued March, 2012, interest at 4.950% payable semi-annually, due April, 2022
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 350	350
Stated interest rate	4.95%
Senior Notes \| Issued March, 2013, interest at 3.875% payable semi-annually, due March, 2023
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 500	500
Stated interest rate	3.875%
Senior Notes \| Issued August 2000, interest at 8.125% payable semiannually, due August 2030 (a)
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 300	300
Stated interest rate	8.125%
Senior Notes \| Issued October 2006, interest at 6.450% payable semiannually, due November 2036
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 300	300
Stated interest rate	6.45%
Senior Notes \| Issued September 2007, interest at 6.750% payable semiannually, due September 2037
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 450	450
Stated interest rate	6.75%
Senior Notes \| Issued March, 2014, interest at 5.600% payable semi-annually, due April, 2044
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 400	400
Stated interest rate	5.60%
Senior Notes \| Revolving credit agreement, weighted-average variable interest rate of 2.014% and 1.572%, as of December 31, 2016 and December 31, 2015, respectively, due May 2019 \| Issued March, 2014, interest at 2.700% payable semi-annually, due April, 2019
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 325	325
Stated interest rate	2.70%
Junior Subordinated Notes \| Issued May 2013, interest at 5.850% payable semiannually, due May 2043
Line of Credit Facility [Line Items]
Debt securities issued amount	$ 550	$ 550
Stated interest rate	5.85%

Debt - Additional Information (Detail)	12 Months Ended
Debt - Additional Information (Detail)	Dec. 31, 2016 USD ($)	May 31, 2016 USD ($)	Apr. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)	Mar. 31, 2015 USD ($)	Feb. 28, 2015 USD ($)
Debt Instrument [Line Items]
Unamortized issuance costs	$ 23,000,000			$ 35,000,000
Letters of credit outstanding	$ 13,000,000
Interest deferment period	5 years
Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 1,250,000,000.00	$ 700,000,000	$ 1,800,000,000.0		$ 1,800,000,000	$ 2,000,000,000
Unamortized issuance costs	$ 10,000,000
Basis spread determined by credit rating	0.45%
Commitment fee percentage	0.30%
Unused capacity under the credit agreement	$ 1,031,000,000
Letters of credit outstanding	$ 24,000,000
Amended and Restated Credit Agreement \| London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Variable rate basis spread	1.45%
Amended and Restated Credit Agreement \| Federal Funds Effective Swap Rate [Member]
Debt Instrument [Line Items]
Variable rate basis spread	0.50%
Amended and Restated Credit Agreement \| London Interbank Offered Rate (LIBOR) Market Index [Member]
Debt Instrument [Line Items]
Variable rate basis spread	1.00%
Amended and Restated Credit Agreement \| Minimum
Debt Instrument [Line Items]
Maximum leverage ratio	1.0
Temporary maximum leverage ratio post-acquisition	1.0
Amended and Restated Credit Agreement \| Maximum
Debt Instrument [Line Items]
Maximum leverage ratio	5.0
Temporary maximum leverage ratio post-acquisition	5.5
Amended and Restated Credit Agreement \| Pro Forma
Debt Instrument [Line Items]
Unused capacity under the credit agreement	$ 970,000,000

Debt - Future Maturities of Long-Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Maturities of Long-term Debt [Abstract]
2017	$ 500
2018	0
2019	970
2020	600
2021	500
Thereafter	2,850
Total principal	5,420
Fair value adjustments related to interest rate swap fair value hedges	24	$ 26
Unamortized issuance costs	(23)	(35)
Unamortized discount	(14)	$ (18)
Total	$ 5,407

Risk Management and Hedging Activities - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Accumulated other comprehensive loss	$ 8	$ 8
Collateral, cash deposits	71
Collateral, letter of credit outstanding	13
Collateral, cash held	5
Collateral, letters of credit received	$ 38
Natural Gas Liquids \| Affiliated Entity
Derivative [Line Items]
Percent of NGL production committed	27.00%
Cash Flow Hedge
Derivative [Line Items]
Accumulated other comprehensive loss	$ 8	8	$ 9
Commodity Derivatives
Derivative [Line Items]
Derivative contracts containing credit-risk related contingent features in net liability position	1
Commodity Derivatives \| Cash Flow Hedge
Derivative [Line Items]
Accumulated other comprehensive loss	$ 6	$ 6	$ 6

Risk Management and Hedging Activities - Summary of Gross and Net Amounts of Derivative Instruments (Detail) - Commodity derivatives - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Values Of Financial Assets And Liabilities Including Derivative Financial Instruments [Line Items]
Gross Amounts of Assets Presented in the Balance Sheet	$ 47	$ 175
Amounts Not Offset in the Balance Sheet - Financial Instruments	0	(1)
Net Amount, Assets	47	174
Gross Amounts of Liabilities Presented in the Balance Sheet	(92)	(81)
Amounts Not Offset in the Balance Sheet - Financial Instruments	0	0
Net Amount, Liabilities	$ (92)	$ (81)

Risk Management and Hedging Activities - Schedule of Designated and Non-Designated Derivative Instruments in Statement of Financial Position, Fair Value (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative Asset [Abstract]
Unrealized gains on derivative instruments - current	$ 42	$ 156
Unrealized gains on derivative instruments - long-term	5	19
Derivative Liability [Abstract]
Unrealized losses on derivative instruments - long-term	(1)	(12)
Commodity Derivatives \| Derivative Asset Not Designated As Hedging Instruments [Member]
Derivative Asset [Abstract]
Unrealized gains on derivative instruments - current	42	156
Unrealized gains on derivative instruments - long-term	5	19
Derivative assets, fair value, total	47	175
Commodity Derivatives \| Derivative Liabilities Not Designated As Hedging Instruments [Member]
Derivative Liability [Abstract]
Unrealized gains on derivative instruments - current	(91)	(69)
Unrealized losses on derivative instruments - long-term	(1)	(12)
Derivative liabilities, fair value, total	$ (92)	$ (81)

Risk Management and Hedging Activities - Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred losses in AOCI (ending balance)	$ (8)
Cash Flow Hedge
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	(9)
Gains (losses) recognized in AOCI on derivatives - effective portion	1
Net deferred losses in AOCI (ending balance)	(8)
Cash Flow Hedge \| Interest Rate Derivatives
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	(4)
Gains (losses) recognized in AOCI on derivatives - effective portion	1
Net deferred losses in AOCI (ending balance)	(3)
Cash Flow Hedge \| Commodity Derivatives
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	(6)
Gains (losses) recognized in AOCI on derivatives - effective portion	0
Net deferred losses in AOCI (ending balance)	(6)
Cash Flow Hedge \| Foreign Currency Derivatives
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net deferred (losses) gains in AOCI (beginning balance)	1
Gains (losses) recognized in AOCI on derivatives - effective portion	0
Net deferred losses in AOCI (ending balance)	$ 1

Risk Management and Hedging Activities - Schedule of Changes in Derivative Instruments not Designated as Hedging Instruments (Detail) - Derivative Assets Not Designated As Hedging Instruments [Member] - Commodity Derivatives - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Realized gains	$ 116	$ 73	$ 45
Unrealized (losses) gains	(139)	46	43
Trading and marketing (losses) gains, net	$ (23)	$ 119	$ 88

Risk Management and Hedging Activities - Schedule of Net Long or Short Positions Expected to be Realized (Detail)	12 Months Ended
	Dec. 31, 2016 MMBTU bbl	Dec. 31, 2015 MMBTU bbl
Crude Oil
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), Year One \| bbl	(1,470,000)	(1,566,672)
Net (Short) Position (Bbls), Year Two \| bbl	(251,000)	(237,000)
Net (Short) Position (Bbls), Year Three \| bbl	(40,000)	0
Net (Short) Position (Bbls), Year Four \| bbl	(50,000)
Natural Gas
Derivative [Line Items]
Net Long (Short) Position (MMBtu), Year One \| MMBTU	(44,981,850)	(25,059,414)
Net Long (Short) Position (MMBtu), Year Two \| MMBTU	0	(7,387,500)
Net Long (Short) Position (MMBtu), Year Three \| MMBTU	0	0
Net Long (Short) Position (MMBtu), Year Four \| MMBTU	0
Natural Gas Liquids
Net (Short) Position, Volume [Abstract]
Net (Short) Position (Bbls), Year One \| bbl	(22,225,821)	(23,575,094)
Net (Short) Position (Bbls), Year Two \| bbl	144,805	(2,082,157)
Net (Short) Position (Bbls), Year Three \| bbl	(2,203)	120,000
Net (Short) Position (Bbls), Year Four \| bbl	240,000
Natural Gas Basis Swaps
Derivative [Line Items]
Net Long (Short) Position (MMBtu), Year One \| MMBTU	6,510,000	2,207,500
Net Long (Short) Position (MMBtu), Year Two \| MMBTU	912,500	4,050,000
Net Long (Short) Position (MMBtu), Year Three \| MMBTU	0	0
Net Long (Short) Position (MMBtu), Year Four \| MMBTU	0

Partnership Equity and Distributions - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued (in shares)	114,749,848	114,742,948
Partnership deadline for distributions (in days)	45 days
Distribution Stage First
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 0.4025
Distribution Stage Second
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 0.4375
Incentive distribution payments and minimum distribution level	13.00%
Distribution Stage Third
Partnership Equity And Distribution [Line Items]
Distribution unitholders and general partner per unit	$ 0.525
Incentive distribution payments and minimum distribution level	23.00%
Distribution Stage Thereafter
Partnership Equity And Distribution [Line Items]
Incentive distribution payments and minimum distribution level	48.00%
General Partner
Partnership Equity And Distribution [Line Items]
General partner ownership interest	0.30%
Limited Partners
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued (in shares)			14,375,000
Price per common unit			$ 48.90
Net proceeds			$ 677
Consideration financed through issuance of common units			4,497,158
Limited partner ownership interest	1.70%
Equity Distribution Agreement
Partnership Equity And Distribution [Line Items]
Offer value of common stock remaining available for sale	$ 349
2014 Equity Distribution Agreement [Member]
Partnership Equity And Distribution [Line Items]
Common unitholders, units issued (in shares)	0	788,033	2,256,066
Proceeds from issuance of common stock		$ 31	$ 119
Offering costs		$ 1	1
Maximum aggregate offering amount			$ 500

Partnership Equity and Distributions - Cash Distribution (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Partnership Equity And Distribution [Line Items]
Total Cash Distribution (Millions)	$ 483	$ 482	$ 420
November 14, 2016
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7800
Total Cash Distribution (Millions)	$ 120
August 12, 2016
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7800
Total Cash Distribution (Millions)	$ 121
May 13, 2016
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7800
Total Cash Distribution (Millions)	$ 121
February 12, 2016
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7800
Total Cash Distribution (Millions)	$ 121
November 13, 2015
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7800
Total Cash Distribution (Millions)	$ 120
August 14, 2015
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7800
Total Cash Distribution (Millions)	$ 121
May 15, 2015
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7800
Total Cash Distribution (Millions)	$ 121
February 13, 2015
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7800
Total Cash Distribution (Millions)	$ 120
November 14, 2014
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7700
Total Cash Distribution (Millions)	$ 117
August 14, 2014
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7575
Total Cash Distribution (Millions)	$ 111
May 15, 2014
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7450
Total Cash Distribution (Millions)	$ 106
February 14, 2014
Partnership Equity And Distribution [Line Items]
Per Unit Distribution	$ 0.7325
Total Cash Distribution (Millions)	$ 86

Equity-Based Compensation (Details) - USD ($) $ in Millions	12 Months Ended
Equity-Based Compensation (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 28, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense	$ 18	$ 8	$ 14
2016 LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units authorized (in shares)				900,000
2005 LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units authorized (in shares)	850,000

Equity-Based Compensation - Fair Value of Unvested Unit-Based Awards (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Strategic Performance Units (SPUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period (years)	3 years
Unrecognized Compensation Expense at December 31, 2016 (millions)	$ 6
Weighted-Average Remaining Vesting (years)	2 years
Strategic Performance Units (SPUs) \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Estimated Forfeiture Rate	0.00%
Strategic Performance Units (SPUs) \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Estimated Forfeiture Rate	11.00%
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Expense at December 31, 2016 (millions)	$ 5
Weighted-Average Remaining Vesting (years)	2 years
Phantom Units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period (years)	1 year
Estimated Forfeiture Rate	0.00%
Phantom Units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period (years)	3 years
Estimated Forfeiture Rate	11.00%

Equity-Based Compensation - Schedule of Units Outstanding (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Strategic Performance Units (SPUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum vesting percentage	200.00%
Vesting period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at beginning of period (in shares)	208,459	219,363	230,900
Granted (in shares)	131,610	111,930	116,790
Forfeited (in shares)	(8,463)	(29,283)	(13,828)
Vested (in shares)	(98,295)	(93,551)	(114,499)
Outstanding at end of period (in shares)	233,311	208,459	219,363
Expected to vest (in shares)	219,844
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Beginning Balance, Grant Date Weighted-Average Price Per Unit (in dollars per share)	$ 48.46	$ 47.89	$ 39.30
Granted, Grant Date Weighted-Average Price Per Unit (in dollars per share)	45.31	43.25	54.05
Forfeited, Grant Date Weighted-Average Price Per Unit (in dollars per share)	46.27	48.02	40.75
Vested, Grant Date Weighted-Average Price Per Unit (in dollars per share)	54.05	41.02	37.72
Ending Balance, Grant Date Weighted-Average Price Per Unit (in dollars per share)	44.41	$ 48.46	$ 47.89
Expected to vest, Grant Date Weighted-Average Price Per Unit (in dollars per share)	44.35
Outstanding at end of period, Measurement Date Weighted Average Price Per Unit (in dollars per share)	45.86
Expected to vest, Measurement Date Weighted Average Price Per Unit (in dollars per share)	$ 45.98
Strategic Performance Units (SPUs) \| 2012
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Vesting percentage			115.00%
Strategic Performance Units (SPUs) \| 2013
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Vesting percentage		115.00%
Strategic Performance Units (SPUs) \| 2014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Vesting percentage	130.00%
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at beginning of period (in shares)	204,368	171,202	207,522
Granted (in shares)	132,870	147,540	122,650
Forfeited (in shares)	(3,240)	(17,400)	(11,130)
Vested (in shares)	(126,681)	(96,974)	(147,840)
Outstanding at end of period (in shares)	207,317	204,368	171,202
Expected to vest (in shares)	185,785
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Beginning Balance, Grant Date Weighted-Average Price Per Unit (in dollars per share)	$ 49.85	$ 48.11	$ 40.18
Granted, Grant Date Weighted-Average Price Per Unit (in dollars per share)	45.33	47.84	53.73
Forfeited, Grant Date Weighted-Average Price Per Unit (in dollars per share)	48.62	48.40	41.96
Vested, Grant Date Weighted-Average Price Per Unit (in dollars per share)	50.13	44.00	42.10
Ending Balance, Grant Date Weighted-Average Price Per Unit (in dollars per share)	46.80	$ 49.85	$ 48.11
Expected to vest, Grant Date Weighted-Average Price Per Unit (in dollars per share)	46.72
Outstanding at end of period, Measurement Date Weighted Average Price Per Unit (in dollars per share)	45.97
Expected to vest, Measurement Date Weighted Average Price Per Unit (in dollars per share)	$ 45.90

Equity-Based Compensation - Fair Value of Awards Vested (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Strategic Performance Units (SPUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units vested (in shares)	98,295	93,551	114,499
Fair Value of Units Vested	$ 7	$ 4	$ 7
Unit-Based Liabilities Paid	$ 4	$ 7	$ 8
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units vested (in shares)	126,681	96,974	147,840
Fair Value of Units Vested	$ 4	$ 3	$ 5
Unit-Based Liabilities Paid	$ 5	$ 5	$ 5

Benefits (Details) - USD ($) $ in Millions	12 Months Ended
Benefits (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Contribution Plan Disclosure [Line Items]
Minimum age	18 years
Eligibility minimum hours per week	20 hours
Automatic enrollment percentage	6.00%
Employer matching contribution, percent of employees' gross pay	6.00%
Defined contribution plan cost	$ 29	$ 32	$ 30
Minimum
Defined Contribution Plan Disclosure [Line Items]
Employer discretionary contribution percentage	4.00%
Maximum
Defined Contribution Plan Disclosure [Line Items]
Employer discretionary contribution percentage	7.00%

Net Income or Loss per Limited Partner Unit - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Dilutive potential units (in shares)	1,105	7,038	10,574

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Current Federal Tax Expense (Benefit)	$ (19)	$ 0	$ 0
Current State and Local Tax Expense (Benefit)	(2)	0	(2)
Deferred Federal Income Tax Expense (Benefit)	(22)	97	0
Deferred State and Local Income Tax Expense (Benefit)	(3)	5	(9)
Income tax expense	$ (46)	$ 102	$ (11)

Income Taxes Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Net operating loss	$ 0	$ 58,000,000
Total deferred income tax assets	0	58,000,000
Property, plant and equipment and intangibles - federal	0	(35,000,000)
Property, plant and equipment and intangibles - state	(28,000,000)	(26,000,000)
Total deferred income tax liabilities	28,000,000	61,000,000
Net deferred income tax liabilities	(28,000,000)	(3,000,000)
Deferred income tax assets, net - noncurrent	0	23,000,000
Deferred income tax liabilities, net - noncurrent	(28,000,000)	(26,000,000)
Reduction to net federal deferred tax asset	$ 58,000,000
Federal net operating losses		$ 163,000,000
Texas margin tax	0.75%	0.75%	0.95%

Commitments and Contingent Liabilities (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Rent expense		$ 37	$ 34	$ 31
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2017		61
2018		37
2019		35
2020		29
2021		21
Thereafter		42
Total minimum rental payments		225
Large Producer in DJ Basin
Loss Contingencies [Line Items]
Cash payment	$ 89
Dedication term	15 years
Legal fees		2
Other Current Liabilities
Loss Contingencies [Line Items]
Environmental Liabilities		4	3
Other Long-Term Liabilities
Loss Contingencies [Line Items]
Environmental Liabilities		$ 9	$ 9

Restructuring Costs (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
Restructuring Costs (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015
Restructuring Cost and Reserve [Line Items]
Expected number of positions eliminated, percent	10.00%
Restructuring costs			$ 11
Further severance costs		$ 1
One-time Employee Termination
Restructuring Cost and Reserve [Line Items]
Restructuring costs		13
Current Liabilities \| One-time Employee Termination
Restructuring Cost and Reserve [Line Items]
Restructuring costs		$ 1

Business Segments - Segment Information (Detail) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2016 USD ($) segment	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Segment Reporting Information [Line Items]
Number of reporting segments \| segment									2
Total operating revenue	$ 1,983	$ 1,823	$ 1,623	$ 1,464	$ 1,691	$ 1,870	$ 1,849	$ 2,020	$ 6,893	$ 7,430	$ 14,025
Gross margin									1,432	1,449	2,197
Operating and maintenance expense									(670)	(732)	(773)
Depreciation and amortization expense									(378)	(377)	(348)
General and administrative expense									(292)	(281)	(277)
Asset impairments									0	912	18
Other (income) and expense, net									65	(10)	(7)
Earnings from unconsolidated affiliates									282	184	82
Interest expense, net									(321)	(320)	(287)
Gain on sale of assets, net		35							35	42	(7)
Restructuring Charges		(13)							(13)	(11)	0
Income tax (expense) benefit									(46)	102	(11)
Net income (loss)	(39)	89	(21)	65	(382)	24	(491)	(17)	94	(866)	551
Net income attributable to non-controlling interests	(5)	0	(1)	0	(4)	(1)	0	0	(6)	(5)	(4)
Net income (loss) attributable to partners	$ (44)	$ 89	$ (22)	$ 65	$ (386)	$ 23	$ (491)	$ (17)	88	(871)	547
Non-cash derivative mark-to-market									(139)	46	43
Non-cash lower of cost or market adjustments									3	8	24
Capital expenditures									144	811	1,384
Investments in unconsolidated affiliates, net									53	64	161
Operating Segments \| Gathering and Processing
Segment Reporting Information [Line Items]
Total operating revenue									4,490	4,910	9,873
Gross margin									1,227	1,213	1,971
Operating and maintenance expense									(611)	(668)	(725)
Depreciation and amortization expense									(344)	(343)	(315)
General and administrative expense									(14)	(22)	(27)
Asset impairments										876	18
Other (income) and expense, net									73	(1)	(5)
Earnings from unconsolidated affiliates									73	54	5
Interest expense, net									0	0	0
Gain on sale of assets, net									19	42	(7)
Restructuring Charges									0	0
Income tax (expense) benefit									0	0	0
Net income (loss)									423	(601)	879
Net income attributable to non-controlling interests									(6)	(5)	(4)
Net income (loss) attributable to partners									417	(606)	875
Non-cash derivative mark-to-market									(119)	47	39
Non-cash lower of cost or market adjustments									0	0	0
Capital expenditures									107	729	1,272
Investments in unconsolidated affiliates, net									1	15	75
Operating Segments \| Logistics and Marketing
Segment Reporting Information [Line Items]
Total operating revenue									6,186	6,487	12,649
Gross margin									205	236	226
Operating and maintenance expense									(43)	(49)	(44)
Depreciation and amortization expense									(15)	(16)	(17)
General and administrative expense									(9)	(11)	(14)
Asset impairments										9	0
Other (income) and expense, net									(5)	(8)	0
Earnings from unconsolidated affiliates									209	130	77
Interest expense, net									0	0	0
Gain on sale of assets, net									16	0	0
Restructuring Charges									0	0
Income tax (expense) benefit									0	0	0
Net income (loss)									358	273	228
Net income attributable to non-controlling interests									0	0	0
Net income (loss) attributable to partners									358	273	228
Non-cash derivative mark-to-market									(20)	(1)	4
Non-cash lower of cost or market adjustments									3	8	24
Capital expenditures									10	52	62
Investments in unconsolidated affiliates, net									52	49	86
Other
Segment Reporting Information [Line Items]
Total operating revenue									0	0	0
Gross margin									0	0	0
Operating and maintenance expense									(16)	(15)	(4)
Depreciation and amortization expense									(19)	(18)	(16)
General and administrative expense									(269)	(248)	(236)
Asset impairments										27	0
Other (income) and expense, net									(3)	(1)	(2)
Earnings from unconsolidated affiliates									0	0	0
Interest expense, net									(321)	(320)	(287)
Gain on sale of assets, net									0	0	0
Restructuring Charges									(13)	(11)
Income tax (expense) benefit									(46)	102	(11)
Net income (loss)									(687)	(538)	(556)
Net income attributable to non-controlling interests									0	0	0
Net income (loss) attributable to partners									(687)	(538)	(556)
Non-cash derivative mark-to-market									0	0	0
Non-cash lower of cost or market adjustments									0	0	0
Capital expenditures									27	30	50
Investments in unconsolidated affiliates, net									0	0	0
Eliminations
Segment Reporting Information [Line Items]
Total operating revenue									(3,783)	(3,967)	(8,497)
Gross margin									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Asset impairments										0	0
Other (income) and expense, net									0	0	0
Earnings from unconsolidated affiliates									0	0	0
Interest expense, net									0	0	0
Gain on sale of assets, net									0	0	0
Restructuring Charges									0	0
Income tax (expense) benefit									0	0	0
Net income (loss)									0	0	0
Net income attributable to non-controlling interests									0	0	0
Net income (loss) attributable to partners									0	0	0
Non-cash derivative mark-to-market									0	0	0
Non-cash lower of cost or market adjustments									0	0	0
Capital expenditures									0	0	0
Investments in unconsolidated affiliates, net									$ 0	$ 0	$ 0

Business Segments - Segment Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Segment long-term assets	$ 12,617	$ 13,081
Current assets	994	804
Total assets	13,611	13,885
Operating Segments \| Gathering and Processing
Segment Reporting Information [Line Items]
Segment long-term assets	9,053	9,431
Operating Segments \| Logistics and Marketing
Segment Reporting Information [Line Items]
Segment long-term assets	3,278	3,339
Other
Segment Reporting Information [Line Items]
Segment long-term assets	$ 286	$ 311

- Definition

Sum of the carrying amounts as of the balance sheet date of all assets that are expected to be realized in cash, sold or consumed after one year or beyond the normal operating cycle, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(14))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(10))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(12))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(15))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(11))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(13))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(17))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(16))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

+ Details

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest, net of amounts capitalized	$ 306	$ 293	$ 274
Cash paid for income taxes, net of income tax refunds	2	3	4
Property, plant and equipment acquired with accounts payable	27	35	145
Other non-cash changes in property, plant and equipment	(3)	(19)	27
Contribution of assets from our predecessor	$ 0	$ 1,500	$ 0

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Total operating revenue	$ 1,983	$ 1,823	$ 1,623	$ 1,464	$ 1,691	$ 1,870	$ 1,849	$ 2,020	$ 6,893	$ 7,430	$ 14,025
Operating income (loss)	19	92	(12)	80	(466)	57	(463)	40	179	(832)	767
Net income (loss)	(39)	89	(21)	65	(382)	24	(491)	(17)	94	(866)	551
Net income attributable to non-controlling interests	(5)	0	(1)	0	(4)	(1)	0	0	(6)	(5)	(4)
Net income (loss) attributable to partners	(44)	89	(22)	65	(386)	23	(491)	(17)	88	(871)	547
Net loss attributable to predecessor operations	(119)	(31)	(67)	(7)	(476)	(48)	(489)	(86)	(224)	(1,099)	130
Net income allocable to limited partners	$ 44	$ 89	$ 14	$ 41	$ 59	$ 40	$ (33)	$ 38	$ 188	$ 104	$ 303
Basic and diluted net income per limited partner unit (in dollars per share)	$ 0.38	$ 0.78	$ 0.12	$ 0.36	$ 0.51	$ 0.35	$ (0.29)	$ 0.33	$ 1.64	$ 0.91	$ 2.84

Supplementary Information - Condensed Consolidating Financial Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016
Parent Guarantor
Parent Company Only Financial Information [Line Items]
Ownership interest percentage in subsidiary	100.00%

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
ASSETS
Cash and cash equivalents	$ 1	$ 3	$ 27	$ 31	$ 31
Accounts receivable, net	792	544
Inventories	72	51
Other	129	206
Total current assets	994	804
Property, plant and equipment, net	9,069	9,428
Goodwill and intangible assets, net	373	391
Advances receivable - consolidated subsidiaries	0	0
Investments in consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	2,969	2,992
Other long-term assets	206	270
Total assets	13,611	13,885
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	1,123	899
Current maturities of long-term debt	500	0
Advances payable - consolidated subsidiaries	0	0
Long-term debt	4,907	5,669
Other long-term liabilities	228	225
Total liabilities	6,758	6,793
Commitments and contingent liabilities
Equity:
Net equity	6,829	7,067
Accumulated other comprehensive loss	(8)	(8)
Total partners’ equity	6,821	7,059
Non-controlling interests	32	33
Total equity	6,853	7,092	5,215	4,385
Total liabilities and equity	13,611	13,885
Reportable Legal Entities \| Parent Guarantor
ASSETS
Cash and cash equivalents	0	0	0	0
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	0	0
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable - consolidated subsidiaries	2,953	3,436
Investments in consolidated subsidiaries	3,868	3,623
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	6,821	7,059
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	0
Current maturities of long-term debt	0
Advances payable - consolidated subsidiaries	0
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	0	0
Commitments and contingent liabilities
Equity:
Net equity	6,821	7,059
Accumulated other comprehensive loss	0	0
Total partners’ equity	6,821	7,059
Non-controlling interests	0	0
Total equity	6,821	7,059
Total liabilities and equity	6,821	7,059
Reportable Legal Entities \| Subsidiary Issuer
ASSETS
Cash and cash equivalents	0	0	24	17
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	0	0
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable - consolidated subsidiaries	2,760	3,353
Investments in consolidated subsidiaries	6,587	6,011
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	9,347	9,364
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	72	72
Current maturities of long-term debt	500
Advances payable - consolidated subsidiaries	0	0
Long-term debt	4,907	5,669
Other long-term liabilities	0	0
Total liabilities	5,479	5,741
Commitments and contingent liabilities
Equity:
Net equity	3,871	3,626
Accumulated other comprehensive loss	(3)	(3)
Total partners’ equity	3,868	3,623
Non-controlling interests	0	0
Total equity	3,868	3,623
Total liabilities and equity	9,347	9,364
Reportable Legal Entities \| Non-Guarantor Subsidiaries
ASSETS
Cash and cash equivalents	1	3	3	14
Accounts receivable, net	792	544
Inventories	72	51
Other	129	206
Total current assets	994	804
Property, plant and equipment, net	9,069	9,428
Goodwill and intangible assets, net	373	391
Advances receivable - consolidated subsidiaries	0	0
Investments in consolidated subsidiaries	0	0
Investments in unconsolidated affiliates	2,969	2,992
Other long-term assets	206	270
Total assets	13,611	13,885
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	1,051	827
Current maturities of long-term debt	0
Advances payable - consolidated subsidiaries	5,713	6,789
Long-term debt	0	0
Other long-term liabilities	228	225
Total liabilities	6,992	7,841
Commitments and contingent liabilities
Equity:
Net equity	6,592	6,016
Accumulated other comprehensive loss	(5)	(5)
Total partners’ equity	6,587	6,011
Non-controlling interests	32	33
Total equity	6,619	6,044
Total liabilities and equity	13,611	13,885
Consolidating Adjustments
ASSETS
Cash and cash equivalents	0	0	$ 0	$ 0
Accounts receivable, net	0	0
Inventories	0	0
Other	0	0
Total current assets	0	0
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Advances receivable - consolidated subsidiaries	(5,713)	(6,789)
Investments in consolidated subsidiaries	(10,455)	(9,634)
Investments in unconsolidated affiliates	0	0
Other long-term assets	0	0
Total assets	(16,168)	(16,423)
LIABILITIES AND EQUITY
Accounts payable and other current liabilities	0	0
Current maturities of long-term debt	0
Advances payable - consolidated subsidiaries	(5,713)	(6,789)
Long-term debt	0	0
Other long-term liabilities	0	0
Total liabilities	(5,713)	(6,789)
Commitments and contingent liabilities
Equity:
Net equity	(10,455)	(9,634)
Accumulated other comprehensive loss	0	0
Total partners’ equity	(10,455)	(9,634)
Non-controlling interests	0	0
Total equity	(10,455)	(9,634)
Total liabilities and equity	$ (16,168)	$ (16,423)

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, NGLs and condensate to affiliates									$ 6,269	$ 6,779	$ 13,420
Transportation, storage and processing to affiliates									647	532	517
Trading and marketing (losses) gains, net									(23)	119	88
Total operating revenues	$ 1,983	$ 1,823	$ 1,623	$ 1,464	$ 1,691	$ 1,870	$ 1,849	$ 2,020	6,893	7,430	14,025
Purchases of natural gas and NGLs from affiliates									5,461	5,981	11,828
Operating and maintenance expense									670	732	773
Depreciation and amortization expense									378	377	348
General and administrative expense									292	281	277
Asset impairments									0	912	18
Other (income) expense, net									(65)	10	7
Restructuring costs		13							13	11	0
(Gain) loss on sale of assets, net		(35)							(35)	(42)	7
Total operating costs and expenses									6,714	8,262	13,258
Operating income (loss)	19	92	(12)	80	(466)	57	(463)	40	179	(832)	767
Interest expense, net									(321)	(320)	(287)
Earnings from unconsolidated affiliates									282	184	82
Income from consolidated subsidiaries									0	0	0
Income (loss) before income taxes									140	(968)	562
Income tax (expense) benefit									(46)	102	(11)
Net income (loss)	(39)	89	(21)	65	(382)	24	(491)	(17)	94	(866)	551
Net income attributable to non-controlling interests	(5)	0	(1)	0	(4)	(1)	0	0	(6)	(5)	(4)
Net income (loss) attributable to partners	$ (44)	$ 89	$ (22)	$ 65	$ (386)	$ 23	$ (491)	$ (17)	88	(871)	547
Reportable Legal Entities \| Parent Guarantor
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, NGLs and condensate to affiliates									0	0	0
Transportation, storage and processing to affiliates									0	0	0
Trading and marketing (losses) gains, net									0	0	0
Total operating revenues									0	0	0
Purchases of natural gas and NGLs from affiliates									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Asset impairments										0	0
Other (income) expense, net									0	0	0
Restructuring costs									0	0
(Gain) loss on sale of assets, net									0	0	0
Total operating costs and expenses									0	0	0
Operating income (loss)									0	0	0
Interest expense, net									0	0	0
Earnings from unconsolidated affiliates									0	0	0
Income from consolidated subsidiaries									88	(871)	547
Income (loss) before income taxes									88	(871)	547
Income tax (expense) benefit									0	0	0
Net income (loss)									88	(871)	547
Net income attributable to non-controlling interests									0	0	0
Net income (loss) attributable to partners									88	(871)	547
Reportable Legal Entities \| Subsidiary Issuer
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, NGLs and condensate to affiliates									0	0	0
Transportation, storage and processing to affiliates									0	0	0
Trading and marketing (losses) gains, net									0	0	0
Total operating revenues									0	0	0
Purchases of natural gas and NGLs from affiliates									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Asset impairments										0	0
Other (income) expense, net									0	0	0
Restructuring costs									0	0
(Gain) loss on sale of assets, net									0	0	0
Total operating costs and expenses									0	0	0
Operating income (loss)									0	0	0
Interest expense, net									(321)	(320)	(287)
Earnings from unconsolidated affiliates									0	0	0
Income from consolidated subsidiaries									409	(551)	834
Income (loss) before income taxes									88	(871)	547
Income tax (expense) benefit									0	0	0
Net income (loss)									88	(871)	547
Net income attributable to non-controlling interests									0	0	0
Net income (loss) attributable to partners									88	(871)	547
Reportable Legal Entities \| Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, NGLs and condensate to affiliates									6,269	6,779	13,420
Transportation, storage and processing to affiliates									647	532	517
Trading and marketing (losses) gains, net									(23)	119	88
Total operating revenues									6,893	7,430	14,025
Purchases of natural gas and NGLs from affiliates									5,461	5,981	11,828
Operating and maintenance expense									670	732	773
Depreciation and amortization expense									378	377	348
General and administrative expense									292	281	277
Asset impairments										912	18
Other (income) expense, net									(65)	10	7
Restructuring costs									13	11
(Gain) loss on sale of assets, net									(35)	(42)	7
Total operating costs and expenses									6,714	8,262	13,258
Operating income (loss)									179	(832)	767
Interest expense, net									0	0	0
Earnings from unconsolidated affiliates									282	184	82
Income from consolidated subsidiaries									0	0	0
Income (loss) before income taxes									461	(648)	849
Income tax (expense) benefit									(46)	102	(11)
Net income (loss)									415	(546)	838
Net income attributable to non-controlling interests									(6)	(5)	(4)
Net income (loss) attributable to partners									409	(551)	834
Consolidating Adjustments
Condensed Financial Statements, Captions [Line Items]
Sales of natural gas, NGLs and condensate to affiliates									0	0	0
Transportation, storage and processing to affiliates									0	0	0
Trading and marketing (losses) gains, net									0	0	0
Total operating revenues									0	0	0
Purchases of natural gas and NGLs from affiliates									0	0	0
Operating and maintenance expense									0	0	0
Depreciation and amortization expense									0	0	0
General and administrative expense									0	0	0
Asset impairments										0	0
Other (income) expense, net									0	0	0
Restructuring costs										0
(Gain) loss on sale of assets, net									0	0	0
Total operating costs and expenses									0	0	0
Operating income (loss)									0	0	0
Interest expense, net									0	0	0
Earnings from unconsolidated affiliates									0	0	0
Income from consolidated subsidiaries									(497)	1,422	(1,381)
Income (loss) before income taxes									(497)	1,422	(1,381)
Income tax (expense) benefit									0	0	0
Net income (loss)									(497)	1,422	(1,381)
Net income attributable to non-controlling interests									0	0	0
Net income (loss) attributable to partners									$ (497)	$ 1,422	$ (1,381)

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statement of Comprehensive Income (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	$ (39)	$ 89	$ (21)	$ 65	$ (382)	$ 24	$ (491)	$ (17)	$ 94	$ (866)	$ 551
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	1	2
Other comprehensive income from consolidated subsidiaries									0	0	0
Total other comprehensive income									0	1	2
Total comprehensive income (loss)									94	(865)	553
Total comprehensive income (loss) attributable to noncontrolling interests									(6)	(5)	(4)
Total comprehensive income (loss) attributable to partners									88	(870)	549
Parent Guarantor
Other comprehensive income (loss):
Other comprehensive income from consolidated subsidiaries									0
Subsidiary Issuer
Other comprehensive income (loss):
Other comprehensive income from consolidated subsidiaries									0
Non-Guarantor Subsidiaries
Other comprehensive income (loss):
Other comprehensive income from consolidated subsidiaries									0
Reportable Legal Entities \| Parent Guarantor
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									88	(871)	547
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries										1	2
Total other comprehensive income									0	1	2
Total comprehensive income (loss)									88	(870)	549
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income (loss) attributable to partners									88	(870)	549
Reportable Legal Entities \| Subsidiary Issuer
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									88	(871)	547
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	1	2
Other comprehensive income from consolidated subsidiaries										0	0
Total other comprehensive income									0	1	2
Total comprehensive income (loss)									88	(870)	549
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income (loss) attributable to partners									88	(870)	549
Reportable Legal Entities \| Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									415	(546)	838
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries										0	0
Total other comprehensive income									0	0	0
Total comprehensive income (loss)									415	(546)	838
Total comprehensive income (loss) attributable to noncontrolling interests									(6)	(5)	(4)
Total comprehensive income (loss) attributable to partners									409	(551)	834
Consolidating Adjustments
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									(497)	1,422	(1,381)
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into earnings									0	0	0
Other comprehensive income from consolidated subsidiaries									0	(1)	(2)
Total other comprehensive income									0	(1)	(2)
Total comprehensive income (loss)									(497)	1,421	(1,383)
Total comprehensive income (loss) attributable to noncontrolling interests									0	0	0
Total comprehensive income (loss) attributable to partners									$ (497)	$ 1,421	$ (1,383)

Supplementary Information - Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	$ 645,000,000	$ 442,000,000	$ 817,000,000
INVESTING ACTIVITIES:
Intercompany transfers	0	0	0
Capital expenditures	(144,000,000)	(811,000,000)	(1,384,000,000)
Acquisition of unconsolidated affiliates			(161,000,000)
Investments in unconsolidated affiliates, net	(53,000,000)	(64,000,000)	(161,000,000)
Proceeds from sale of assets	163,000,000	164,000,000	30,000,000
Net cash used in investing activities	(34,000,000)	(711,000,000)	(1,515,000,000)
FINANCING ACTIVITIES:
Intercompany transfers	0	0	0
Proceeds from long-term debt	3,353,000,000	7,216,000,000	719,000,000
Payments of long-term debt	(3,628,000,000)	(7,196,000,000)	0
Payments of commercial paper, net	0	(1,012,000,000)	(288,000,000)
Payments of deferred financing costs	(5,000,000)	(4,000,000)	(12,000,000)
Proceeds from issuance of common units, net of offering costs	0	31,000,000	1,001,000,000
Net change in advances to predecessor from DCP Midstream, LLC	157,000,000	1,697,000,000	(301,000,000)
Distributions to limited partners and general partner	(483,000,000)	(482,000,000)	(420,000,000)
Distributions to non-controlling interests	(7,000,000)	(5,000,000)	(5,000,000)
Net cash (used in) provided by financing activities	(613,000,000)	245,000,000	694,000,000
Net change in cash and cash equivalents	(2,000,000)	(24,000,000)	(4,000,000)
Cash and cash equivalents, beginning of period	3,000,000	27,000,000	31,000,000
Cash and cash equivalents, end of period	1,000,000	3,000,000	27,000,000
Reportable Legal Entities \| Parent Guarantor
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	0	0	0
INVESTING ACTIVITIES:
Intercompany transfers	483,000,000	(1,049,000,000)	(581,000,000)
Capital expenditures	0	0	0
Acquisition of unconsolidated affiliates			0
Investments in unconsolidated affiliates, net	0	0
Proceeds from sale of assets	0	0	0
Net cash used in investing activities	483,000,000	(1,049,000,000)	(581,000,000)
FINANCING ACTIVITIES:
Intercompany transfers	0	0	0
Proceeds from long-term debt	0	0	0
Payments of long-term debt	0	0
Payments of commercial paper, net		0	0
Payments of deferred financing costs	0	0	0
Proceeds from issuance of common units, net of offering costs		31,000,000	1,001,000,000
Net change in advances to predecessor from DCP Midstream, LLC	0	1,500,000,000	0
Distributions to limited partners and general partner	(483,000,000)	(482,000,000)	(420,000,000)
Distributions to non-controlling interests	0	0	0
Net cash (used in) provided by financing activities	(483,000,000)	1,049,000,000	581,000,000
Net change in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	0	0	0
Reportable Legal Entities \| Subsidiary Issuer
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	(305,000,000)	(311,000,000)	(271,000,000)
INVESTING ACTIVITIES:
Intercompany transfers	585,000,000	1,283,000,000	(141,000,000)
Capital expenditures	0	0	0
Acquisition of unconsolidated affiliates			0
Investments in unconsolidated affiliates, net	0	0
Proceeds from sale of assets	0	0	0
Net cash used in investing activities	585,000,000	1,283,000,000	(141,000,000)
FINANCING ACTIVITIES:
Intercompany transfers	0	0	0
Proceeds from long-term debt	3,353,000,000	7,216,000,000	719,000,000
Payments of long-term debt	(3,628,000,000)	(7,196,000,000)
Payments of commercial paper, net		(1,012,000,000)	(288,000,000)
Payments of deferred financing costs	(5,000,000)	(4,000,000)	(12,000,000)
Proceeds from issuance of common units, net of offering costs		0	0
Net change in advances to predecessor from DCP Midstream, LLC	0	0	0
Distributions to limited partners and general partner	0	0	0
Distributions to non-controlling interests	0		0
Net cash (used in) provided by financing activities	(280,000,000)	(996,000,000)	419,000,000
Net change in cash and cash equivalents	0	(24,000,000)	7,000,000
Cash and cash equivalents, beginning of period	0	24,000,000	17,000,000
Cash and cash equivalents, end of period	0	0	24,000,000
Reportable Legal Entities \| Non-Guarantor Subsidiaries
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	950,000,000	753,000,000	1,088,000,000
INVESTING ACTIVITIES:
Intercompany transfers	0	0	0
Capital expenditures	(144,000,000)	(811,000,000)	(1,384,000,000)
Acquisition of unconsolidated affiliates			(161,000,000)
Investments in unconsolidated affiliates, net	(53,000,000)	(64,000,000)
Proceeds from sale of assets	163,000,000	164,000,000	30,000,000
Net cash used in investing activities	(34,000,000)	(711,000,000)	(1,515,000,000)
FINANCING ACTIVITIES:
Intercompany transfers	(1,068,000,000)	(234,000,000)	722,000,000
Proceeds from long-term debt	0	0	0
Payments of long-term debt	0	0
Payments of commercial paper, net		0	0
Payments of deferred financing costs	0	0	0
Proceeds from issuance of common units, net of offering costs		0	0
Net change in advances to predecessor from DCP Midstream, LLC	157,000,000	197,000,000	(301,000,000)
Distributions to limited partners and general partner	0	0	0
Distributions to non-controlling interests	(7,000,000)	(5,000,000)	(5,000,000)
Net cash (used in) provided by financing activities	(918,000,000)	(42,000,000)	416,000,000
Net change in cash and cash equivalents	(2,000,000)	0	(11,000,000)
Cash and cash equivalents, beginning of period	3,000,000	3,000,000	14,000,000
Cash and cash equivalents, end of period	1,000,000	3,000,000	3,000,000
Consolidating Adjustments
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities	0	0	0
INVESTING ACTIVITIES:
Intercompany transfers	(1,068,000,000)	(234,000,000)	722,000,000
Capital expenditures	0	0	0
Acquisition of unconsolidated affiliates			0
Investments in unconsolidated affiliates, net	0	0
Proceeds from sale of assets	0	0	0
Net cash used in investing activities	(1,068,000,000)	(234,000,000)	722,000,000
FINANCING ACTIVITIES:
Intercompany transfers	1,068,000,000	234,000,000	(722,000,000)
Proceeds from long-term debt	0	0	0
Payments of long-term debt	0	0
Payments of commercial paper, net		0	0
Payments of deferred financing costs	0	0	0
Proceeds from issuance of common units, net of offering costs		0	0
Net change in advances to predecessor from DCP Midstream, LLC	0	0	0
Distributions to limited partners and general partner	0	0	0
Distributions to non-controlling interests	0	0	0
Net cash (used in) provided by financing activities	1,068,000,000	234,000,000	(722,000,000)
Net change in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	$ 0	$ 0	$ 0

Subsequent Events - Additional Information (Detail)	May 17, 2017 USD ($) mi	Apr. 25, 2017 $ / shares	Feb. 14, 2017 $ / shares	Feb. 07, 2017	Feb. 28, 2017 USD ($)	Dec. 31, 2016 USD ($)	May 31, 2016 USD ($)	Apr. 30, 2016 USD ($)	Mar. 31, 2015 USD ($)	Feb. 28, 2015 USD ($)
Amended and Restated Credit Agreement
Subsequent Event [Line Items]
Maximum borrowing capacity						$ 1,250,000,000.00	$ 700,000,000	$ 1,800,000,000.0	$ 1,800,000,000	$ 2,000,000,000
Subsequent Event
Subsequent Event [Line Items]
Distribution of dividend \| $ / shares		$ 0.78	$ 0.78
Dividend date to be paid		May 15, 2017	Feb. 14, 2017
Dividend record date		May 09, 2017		Feb. 07, 2017
Subsequent Event \| Douglas Gathering System
Subsequent Event [Line Items]
Length of pipeline divested \| mi	1,500.00
Proceeds from divestiture of gathering system	$ 128,000,000
Subsequent Event \| Amended and Restated Credit Agreement
Subsequent Event [Line Items]
Maximum borrowing capacity					$ 1,400,000,000.0

Label	Element	Value
Interest Rate Swap [Member] \| Cash Flow Hedging [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	us-gaap_AccumulatedOtherComprehensiveIncomeLossNetOfTax	$ (3,000,000)
Foreign Currency Derivatives [Member] \| Cash Flow Hedging [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	us-gaap_AccumulatedOtherComprehensiveIncomeLossNetOfTax	$ 1,000,000

Fair Value Measurement - Assets Measured at Fair Value On A Non-recurring Basis (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset impairments	$ 0	$ 912,000,000	$ 18,000,000
Goodwill
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset impairments		460,000,000
Property, plant and equipment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset impairments		302,000,000
Intangible assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset impairments		122,000,000
Other assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset impairments		28,000,000
Fair Value, Measurements, Nonrecurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets	$ 0	173,000,000
Fair Value, Measurements, Nonrecurring \| Goodwill
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Property, plant and equipment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		87,000,000
Fair Value, Measurements, Nonrecurring \| Intangible assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		36,000,000
Fair Value, Measurements, Nonrecurring \| Other assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		50,000,000
Fair Value, Measurements, Nonrecurring \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Level 1 \| Goodwill
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Level 1 \| Property, plant and equipment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Level 1 \| Intangible assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Level 1 \| Other assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Level 2 \| Goodwill
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Level 2 \| Property, plant and equipment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Level 2 \| Intangible assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Level 2 \| Other assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		173,000,000
Fair Value, Measurements, Nonrecurring \| Level 3 \| Goodwill
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		0
Fair Value, Measurements, Nonrecurring \| Level 3 \| Property, plant and equipment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		87,000,000
Fair Value, Measurements, Nonrecurring \| Level 3 \| Intangible assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		36,000,000
Fair Value, Measurements, Nonrecurring \| Level 3 \| Other assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets		$ 50,000,000